By Michael Kuser
MARLBOUROUGH, Mass. — Can New England balance reliability, economics and public policy in a fast-changing energy world? How will the region better prepare itself to handle winter cold snaps than in the past?
These and other questions arose at the Northeast Energy and Commerce Association’s 17th Power Markets Conference on Nov. 8. Here are highlights of what we heard.
Internalize, Don’t Politicize
Ashley Brown, executive director of Harvard University’s Electricity Policy Group, said, “My fear today is that we’re moving back to a battle between various special interest groups and further politicizing the sector.”
Resource selection based on economics, reliability and social benefits has given way to state subsidies and mandates that often work against public policy environmental goals, with uneconomic resources chasing bailouts instead of focusing on how to become more efficient, he said.
“Part of the problem … is that we have simply failed to internalize social considerations in economics,” Brown said. “The lack of a carbon policy in the U.S. is not only intellectually bankrupt, but it does in fact penalize emissions-free resources.”
Energy Security Banking
Mark Karl, ISO-NE vice president for market development, said the region is moving into an era in which more resources have less fuel security. The grid operator is concerned the situation will get worse.
Fuel logistics become an issue in winter, whether because of natural gas pipeline constraints, limited dual-fuel storage or reduced ability to deliver oil by truck, he said. The significant retirement of large non-gas-fired generation is an important factor, as is the type of oil used.
“For example, some generators are burning No. 6 oil, which is basically almost asphalt, so in the wintertime, when that stuff gets cold, it gets pretty difficult to pump and move,” Karl said.
The retirement of two nuclear plants and the Brayton Point coal plant in recent years might be good for the environment, but collectively it presents a challenge for reliability, he said.
Karl said ISO-NE is looking to create a new reserve service referred to as “the energy inventory reserve constraint.”
“We’re proposing to incorporate into the real-time market an additional constraint that looks at the ability to provide energy storage or an energy bank,” he said. “I want to be careful here because it’s easy to think about this from the standpoint of conventional generator fuel, but this will apply to any sort of resource that has the ability to maintain essentially a reserve bank of energy that can be converted into electricity when needed.”
The idea is to optimize the use of limited energy over more extended periods compared with how markets are currently designed to optimize energy over the course of an operating day, he said.
Outside the marketplace, operators also worry about the next day and the days that follow, and sometimes order an oil-burning unit offline for a weekend anticipating the need to provide reserves come Monday, “so that’s an out-of-market action that does cause distortions in the marketplace,” Karl said.
Brett Kruse, vice president of market design at Calpine, said ISO-NE could use a six- or seven-day-ahead market to effectively manage storage in a way that avoids having to take out-of-the-market actions.
The proposal could help the RTO manage how it deploys plants day to day and provide an insurance policy to keep a certain amount of storage in the system, he said.
“There are a lot of questions about that and how it would be priced, but it’s conceptually a pretty good idea,” Kruse said.
But he also had some reservations about the plan. “Looking at the way they’re presenting it now, where it’s a voluntary forward market, and won’t have any mitigation, which is a key aspect to go with that, we think it has some potential, although it’s hard to see how a lot of load will come into that,” he said.
David Cavanaugh, vice president of regulatory and market affairs for Energy New England, an energy services firm, said the RTO’s thinking at first glance seems robust, as its design extends beyond the winter period into a period where the bulk power system has more renewables and, perhaps, storage resources.
“I’m not sure the sophistication of this model gets us there … but we can be informed by other interim efforts such as the opportunity cost model set for use this winter,” Cavanaugh said. “I think the design is well thought out … just have some concerns when I look at the multi-day-ahead market, its voluntary participation,” in terms of maintaining adequate fuel stocks.
Abigail Krich, president of Boreas Renewables, said she sees a market design that, “even though it was triggered by fossil fuel issues, could work with that transition to a clean energy system that relies on intermittent generation. It looks like something that makes sure we have a dispatchable store of available energy in reserve.”
“I question whether we need all of these pieces in the proposal or whether we might just use some of them,” Krich said.
Discussing the race for renewables at the state level, Peter Fuller of Autumn Lane Energy Consulting said the tension in these markets is understandable. While consumers have benefited greatly from the markets, and investors and market participants have an expectation that everyone in the market will play by the same set of rules, states pursuing policy objectives don’t necessarily feel bound by those rules. In addition, the states have not been able, individually or collectively, to identify exactly what they want in a way that an RTO can create a market for it, he said.
Rather, states want to maintain control of resource decisions as policy objectives continue to evolve over time. “As much as anything they want to control that,” Fuller said. “If I’m a governor or legislator thinking how I want to transform the energy system in my state, my first instinct is not to send somebody to [the New England Power Pool] or to PJM to offer proposals, to come up with a matrix or a set of market rules and see how that plays out.” States are more likely to take direct action that then can cause dislocations in the markets.
Day Pitney attorney Sebastian Lombardi, who serves as counsel to NEPOOL, said that overlaying all the fuel security and grid resilience efforts is the need for regions to continue to engage in efforts to help bridge the divide between evolving state and federal policies and the market.
“From a state policy perspective, the competitive markets are not always achieving what they’d like the markets to achieve,” Lombardi said.
Darlene Phillips, senior director for strategic policy and external affairs at PJM, explained the RTO’s proposed revamp of its capacity market.
The Extended Resource Carve-out proposal would allow specific, state-subsidized resources to opt out of the capacity market and PJM to adjust market clearing prices as if the resources were still in it. (See related story, PJM Stakeholders Hold Their Lines in Capacity Battle.)
“If you don’t want your subsidized resources to get a minimum offer for price and go into the market, we will allow you to take those resources out of the market,” she said. “One of the things that FERC did not like about our original approach is that we actually paid those resources a payment.”
When it comes to existing renewable resources, PJM’s minimum offer price rule would have very little impact because the price would be zero, she said. The RTO applies a 20-MW threshold to renewables for the MOPR, which most of them don’t meet, though that situation might change with large-scale offshore wind coming along.