WASHINGTON — Generation operators fared better during the early January cold snap than in the 2014 polar vortex, officials told Congress on Tuesday, but New England needs to take urgent action to prevent major reliability problems.
“Although we are still receiving and reviewing data, it appears that, notwithstanding stress in several regions, overall the bulk power system performed relatively well,” FERC Chairman Kevin McIntyre told the Senate Energy and Natural Resources Committee. “There were no customer outages resulting from failures of the bulk power system, generators or transmission lines. … With limited exceptions, the RTOs/ISOs had sufficient reserves to ensure reliable operations.” (See related story, McIntyre Wades into Capitol Hill Fuel Wars.)
Temperatures between Dec. 28 and Jan. 7 were 20 to 35 degrees Fahrenheit below average in many regions, but peak load in eastern markets was slightly below that in 2014, FERC said.
PJM recorded three of its top 10 winter peak demand days of all time. SPP set a new winter demand peak of 42.71 GW on Jan. 16, besting a record set Jan. 2. ERCOT set a new winter peak of 65.73 GW on Jan. 17 — almost 3 GW higher than the previous record of 62.86 GW on Jan. 3. (See ERCOT, SPP Extend Winter Peak Records.)
The MISO South region set a new winter peak of 32.1 GW on Jan. 17, just short of the all-time (summer) peak of 32.6 GW.
Reserves
Only MISO (Jan. 1-5) and NYISO (Jan. 5-7) saw reserve shortages, McIntyre said. Reserve prices for resources that can respond within 10 minutes were more than $1/MWh during 41% of hours in PJM, 39% in NYISO and 72% in MISO.
McIntyre said initial data suggest that generator performance was better than in 2014 but that “a definitive assessment cannot be made at this time.”
PJM reported that forced outages during the peak demand hour of the recent cold blast were less than 23 GW (11%), half the 22% rate during the polar vortex.
Prices
Between Dec. 28 and Jan. 7, ISO-NE recorded the highest average day-ahead prices at $177/MWh, while PJM hit the highest maximum at $375/MWh. (See chart.) Prices last winter ranged from the low $30s to low $40s.
The energy market prices are consistent with the spike in natural gas prices during the period, McIntyre said, although FERC staff are conducting routine screening of market data for any signs of manipulative behavior.
Natural gas spot prices hit $140/MMBtu in New York on Jan. 4, and seven other trading points in the Northeast and Mid-Atlantic had averages above $100. Gas demand on Jan. 1 hit 150.7 billion cubic feet, exceeding the previous single-day record set in 2014, the Energy Information Administration reported.
Oil, LNG Save New England — This Time
Pipelines in the Northeast and parts of the Midwest had frequent delivery limitations during the period. Operational Flow Orders (OFOs) — requiring shippers to balance their supply with their customers’ usage daily within a specified tolerance band — were declared on the Algonquin, Dominion, Iroquois, Tennessee and Texas Eastern pipelines in the Northeast. Most of the OFOs declared during the cold were lifted on or before Jan. 9, FERC said.
New England survived its gas pipeline capacity constraints thanks to LNG shipments and plants switching to oil.
ISO-NE CEO Gordon van Welie, who also testified to the committee Tuesday, expressed frustration that New England has not taken steps to address threats to its reliability given the growth of gas-fired generation since he first told Congress of his concerns in 2013. Since 2000, oil- and coal-fired generation’s share of ISO-NE’s power production has fallen from 40% to less than 10%, while natural gas has risen from 15% to about 50%.
The region will have lost much of its nuclear power with the retirement of Pilgrim in 2019 (Vermont Yankee closed in 2014), leaving only the 2,100-MW Millstone station in Connecticut and the 1,200-MW Seabrook plant in New Hampshire. Dominion Energy has threatened to shutter Millstone if it does not begin earning higher revenues. (See Conn. Regulators Signal Support for Millstone.)
On Jan. 17, ISO-NE released its Operational Fuel-Security Analysis, which examined 23 fuel-mix scenarios using current pipeline infrastructure to determine whether enough fuel would be available to meet demand.
The report concluded that power shortages attributed to inadequate fuel would occur in 19 of the scenarios by winter 2024/2025, requiring use of emergency actions such as voluntary energy conservation and involuntary load-shedding. (See Report: Fuel Security Key Risk for New England Grid.)
“What our study [shows] is we’re really close to the edge in New England, and we need to find a way of relieving this constraint one way or the other,” van Welie told the committee. “Either through investment in pipeline infrastructure or continuing to invest in other sources of energy that will take the pressure off the gas pipelines or reducing demand on the system. Those are the three avenues available to the region.”
Costly
“It will be costly to remedy these fuel-security challenges — whether the region chooses to invest in renewable energy (and related transmission), fuel infrastructure with long-term contracts, or further measures to reduce demand for wholesale electricity and natural gas,” he continued.
“A key question to be addressed will be the level of fuel-security risk that New England is willing to accept.”
Failing to invest, van Welie said, will result in “chronic price spikes during cold weather, higher emissions when it’s more economic to burn oil than natural gas, and the possibility of further interventions by ISO-NE in the wholesale electricity market to try to delay critical resources from retiring.”
With FERC approval, the RTO can sign reliability agreements to delay generator retirements that would cause transmission overloads. Van Welie said the RTO could change its Tariff for authority to delay retirements because of fuel-security risks, but “generation owners may choose to retire their assets regardless of the offer of a reliability agreement.”
In addition to considering Tariff changes, the RTO will be looking at the impact of a pending rule change: The Pay-for-Performance program, which increases penalties for generator nonperformance, takes effect June 1.
ISO-NE also will be looking at the impact of its Competitive Auctions with Sponsored Policy Resources (CASPR) proposal, filed with FERC on Jan. 8. “While this is a positive step toward accommodating policy-driven resources in the wholesale markets, it may exacerbate the fuel-security challenge if certain non-natural gas-fired generation were to retire before the region has addressed the fuel infrastructure constraints highlighted in the Operational Fuel-Security Analysis,” van Welie said. (See ISO-NE Files CASPR Proposal.)
PJM Pushes Price Formation Plan
PJM said it “had an abundance of reserves and capacity” during the cold spell.
“In most respects, the recent cold snap was much milder than the polar vortex,” PJM CEO Andy Ott said in his written testimony to the committee. “The temperatures were not as low, the wind chill was much less and the demand for electricity was lower, in part due to the cold snap occurring during a holiday week. On the flip side, the cold snap did last for much longer, which led to some degrading of generator performance over time.”
Ott used some of his time before the committee to promote the RTO’s proposal to allow inflexible generators, including coal and nuclear plants, to set LMPs. (See “PJM Wins Examination of Price Formation,” PJM Markets and Reliability Committee Briefs: Dec. 21, 2017.)
He said the proposal would increase energy prices while reducing uplift and capacity prices.
“While out-of-market payments have improved since the polar vortex (approximately $16 million per day) we still saw significant payments during the recent event (approximately $4 million per day),” Ott said. “By contrast, on a typical day, out-of-market payments may be approximately $400,000 to $500,000.”
The ‘Next Level’ for Gas-Electric Coordination
Ott also called for “bringing gas-electric coordination to the next level.”
“To reach this next level, we believe it is important that FERC, [the Department of Energy] and, in some cases, this committee look into some key dichotomies in the regulation of these vital infrastructures.”
While the electric industry is subject to mandatory physical and cybersecurity standards under FERC, the gas pipeline industry uses “high-level voluntary guidelines” from the Transportation Security Administration “augmented with yet a different level of regulation by the Pipeline and Hazardous Materials Safety Administration,” Ott said.
“I say this not to impugn work that the pipelines have done in this area but to point out that the two industries face vastly different compliance obligations, particularly in the area of cybersecurity. By definition, these dichotomies will inevitably hinder an optimal integrated and coordinated approach to common threats from both physical and cyberattack.”
Tightening CEII?
Ott also suggested changing the handling of critical electric infrastructure information (CEII) to balance transparency with security concerns.
“The CEII rules utilized at FERC and at the state level are designed around a ‘right to know’ approach, with some verification of the bona fides of the requestor. Yet, the federal government doesn’t approach classified information this way,” Ott said. “Rather, that system is based on the provision of access based on a demonstrated ‘need to know.’ It may be time to consider evolving our release of a limited set of highly sensitive infrastructure information from a ‘right to know’ to a ‘need to know’ basis.”
