ISO study warns of precarious energy future; Most scenarios envision emergency actions, including rolling blackouts
A new study by the operator of the region’s power grid warns that without additional natural gas pipeline capacity New England will face a precarious energy future, where emergency actions such as rolling blackouts are likely to become a reality on several days a year.
The fuel security study by ISO-New England examined 23 different scenarios for electricity generation during the winter of 2024-2025 and found that in all but the most optimistic case some sort of emergency action would be necessary. In addition to rolling blackouts, where power to a rotating group of customers is turned off temporarily to reduce pressure on the grid, other emergency measures include tapping the system’s last-resort operating reserves and appeals to the public to reduce energy usage.
“Current trends are pushing the New England power system on a path toward greater fuel-security risks,” the report warned. It called for collaboration among the six New England states to address the risks, and suggested it may be necessary for the grid operator to seek authority to pay nuclear and oil-fired power plants more money to continue operating and not retire.
While the study appeared to warn of what could happen without additional gas pipeline infrastructure, the president of ISO-New England said the goal of the report was not to bolster support for a new pipeline. Gordon van Welie said the report was an acknowledgement that more pipeline capacity was not going to get built, primarily because of political opposition in Massachusetts, steep financial hurdles, and growing resistance to new pipelines in New York. Van Welie said it was time for policymakers to move on to Plan B.
“Just looking at the landscape, it looks pretty pessimistic for new pipeline infrastructure, so the region is going to have to work with what we’ve got,” he said.
What we’ve got is a system that is heavily reliant on natural gas, but lacking sufficient pipeline capacity to meet the demand for gas for both heat and power generation during cold winter periods like the region experienced in late December and early January. In such situations, the region’s fuel mix for electricity generation shifts away from natural gas and toward nuclear power, oil, and coal.
The recent cold snap was an early preview of what’s to come. As more natural gas was used to heat homes, pipeline constraints forced up the price of natural gas and prompted generators to switch to oil and coal. Oil, which normally accounts for 1-2 percent of electricity generation, was the fuel used to produce a third of the region’s electricity during the brief cold snap. More than 2 million barrels of oil were burned over 15 days – more than was burned during the rest of 2017 and all of 2016 combined.
Toward the end of the 15-day period, the grid operator ordered generators to cut back on their use of oil to avoid depleting the available stocks. Van Welie said the situation was touch and go toward the end of the 15-day period. “During the tail end of that cold snap, we were very poorly positioned to survive a large contingency on the system,” he said.
ISO-New England’s job is to keep the lights on, but the new study suggests that task will be complicated over the coming years. Still, there are so many variables involved – weather, power plant retirements, the growth of renewables, the embrace of liquefied natural gas, and the development of battery storage technology to name a few – that it’s difficult to accurately predict the future. The study ignored the relative cost of various forms of energy in assembling its analysis,
The study developed a reference case based on current trends and weather patterns from the winter of 2014-2015. It assumed plants capable of generating 1,500 megawatts of electricity would retire and the region would offset those retirements with LNG imports of 1 billion cubic feet a day, electricity imports of 2,500 megawatts, and 6,600 megawatts of renewables. Generators capable of producing electricity with either gas or oil would receive two deliveries of oil over the winter under the reference case.
Under those conditions, the study forecast 14 hours of rolling blackouts over six days. The study estimated the system would operate with its last-resort reserves for over 53 hours. The study said other emergency measures, including appeals to the public to conserve energy, would be implemented over 76 hours.
Van Welie said all of the emergency measures are rarely used by the regional grid operator. Aides said the last time rolling blackouts were implemented was in 2012 for less than an hour after a lightning strike damaged the transmission system in the Boston area. Prior to that, rolling blackouts were implemented in Connecticut to help stabilize the grid after the Northeast blackout of 2003, which plunged parts of New York City into darkness.
Seven scenarios were more optimistic than the ISO’s reference case, assuming, for example, more LNG imports, more renewables, and more oil shipments to power plants capable of running on oil. In each instance, the amount of emergency actions declined to minimal levels, although a few hours of rolling blackouts were forecast with three of the scenarios.
The remaining scenarios tweaked key variables or combinations of variables in negative directions or forecast what would happen if winter-long outages occurred at one of four key facilities, including a compressor station on a major natural gas pipeline, the Millstone Nuclear Power Station in Connecticut, and LNG import facilities in Boston and New Brunswick.
The study indicated the Millstone and compressor station outages, along with higher-than-expected retirements of existing power plants, would prompt the most blackouts and other emergency measures.
The study’s projections about electricity imports and renewables seemed very conservative. For example, the reference case assumed no offshore wind and no new clean energy imports from Canada by 2024. Yet Massachusetts is in the midst of offshore wind and clean energy procurements that are likely to bring new power to the region before then. (After this story was posted, a spokeswoman for ISO-New England disputed the notion that the agency’s projections for imports and renewables in 2024 were conservative, noting that 10 scenarios incorporate higher levels of renewables and imports than the reference case. Several scenarios raised the level of renewables from 6,600 megawatts to 8,000 megawatts, including 1,400 megawatts from offshore wind. Some scenarios also increased imports from the reference case level of 2,500 megawatts to as much as 3,500 megawatts, including a 1,000-megawatt transmission line from Quebec proposed by several firms participating in the Massachusetts clean energy procurement.)
The ISO study could factor into the state’s deliberations on the offshore wind procurement. The three companies vying for power contracts have different views on how quickly the 1,600 megawatt procurement should be awarded. One competitor wants the state to award bigger contracts faster, while another favors smaller procurements that would allow time for a land-based support industry to develop in Massachusetts. The ISO study suggests bigger procurements could be more advantageous for the state’s energy reliability.
Power plant retirements could be the biggest wildcard for the region. The reference case assumed the retirement by 2024 of plants capable of generating 1,500 megawatts of electricity. But a worst-case scenario indicated retirements could lead to the shutdown of as much as 4,500 megawatts of generating capability. Van Welie said oil and nuclear power plants are likely to face increasing financial and, in the case of oil, environmental pressure to retire. He predicted plants that run on oil will find it harder and hard to run.
“Over time what’s going to happen is we’re going to see the retirement of this fleet,” he said. “That’s a desirable thing from a policy point of view because we won’t achieve decarbonization unless they retire. On the other hand, we are dependent on them, particularly with the fuel constraints that we have. So it’s a real conundrum.”
Van Welie said it may be necessary to find a way to make it financially attractive for uneconomical power plants to remain in operation. Still, he said, there are no guarantees. He said the ISO offered the coal-fired Brayton Point power plant financial incentives to stay open but the plant’s owners decided to shut it down anyway.
Van Welie described his organization’s study as a reality check, a way to kick-start discussions among the six New England states about how to address the region’s future fuel security. He said doing nothing is not an option.
“If the constraints are not relieved, we will, over time, increase the risk profile of the system. What the study shows is that that could end up with fairly severe reliability consequences,” he said. “There’s a cost to doing nothing. There’s a cost of inaction.”
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