(Repeats SEPT 29 story. No change to text.)
By John Kemp
LONDON, Sept 29 (Reuters) - The U.S. Department of Energy has thrown a lifeline to the struggling U.S. coal and nuclear industries by proposing a new rule that would explicitly compensate them for contributing to electric grid reliability and resiliency.
Invoking his powers under the Department of Energy Organization Act, Energy Secretary Rick Perry has directed the Federal Energy Regulatory Commission (FERC) to consider a new grid resiliency rule.
The proposed rule would require independent system operators (ISOs) and regional transmission organisation (RTOs) regulated by FERC to implement new electricity market rules compensating eligible power producers for their contributions to reliability and resiliency.
“Specifically, the (proposed) rule allows for the recovery of costs of fuel-secure generation units that make our grid reliable and resilient,” Perry wrote in a letter to FERC dated Sept. 28.
“Such resources provide reliable capacity, resilient generation, frequency and voltage support, (and) on-site fuel inventory,” he explained. “The rule allows the full recovery costs of certain eligible units.”
“Eligible units must ... be able to provide essential energy and ancillary reliability services and have a 90-day fuel supply on-site in the event of supply disruptions caused by emergencies, extreme weather, or natural or man-made disasters.”
The proposed rule would require ISOs and RTOs to establish “just and reasonable” tariffs for eligible units to recover their full costs and earn a fair rate of return.
U.S. coal-fired and nuclear power producers have complained that the combination of cheap natural gas and growing output from wind and solar power has depressed power market prices.
Power prices are now so low in some markets that many coal-fired and nuclear power plants are struggling to cover their long-term costs and are opting to close rather than pay for expensive maintenance and upgrades.
Perry noted 531 coal-fired units representing around 59 gigawatts (GW) of generating capacity had closed between 2002 and 2016 with another 12.7 GW scheduled to retire through 2020.
Nuclear generators announced the retirement of 4.7 GW of capacity between 2002 and 2016 and have announced a further 7.2 GW of retirements since 2016.
Power markets already regulate and pay power producers for providing a mix of output (GW) and ancillary services.
Ancillary services typically include frequency regulation, voltage control, reactive power, stand-by generation and black start capability, all of which contribute to the reliability and resilience of the grid.
But for the most part markets compensate power producers for actual generation, with only relatively minor payments for ancillary services and resiliency.
Perry wants FERC to order ISOs and RTOs to identify and compensate ancillary services contributing to reliability more explicitly and likely at a higher level.
“There is a growing recognition that ... markets do not necessarily pay generators for all the attributes that they provide to the grid, including resiliency.”
The stipulation that “eligible units” must have 90 days of fuel stored on site makes clear that the rule is clearly intended to benefit coal-fired and nuclear generating units.
Solar and wind farms do not store fuel and gas-fired power plants do not stockpile anything like 90 days of gas on site, relying instead on pipeline deliveries.
“Supply chain disruptions can impact many generators during a widespread fuel shortage event,” according to a recent study written by Department of Energy staff.
“Nuclear and coal plants have advantages associated with onsite fuel storage”, the study noted (“Staff Report to the Secretary on Electricity Markets and Reliability”, DOE, Aug 2017).
Perry has intervened in a long-running debate about how best to safeguard the reliability and resiliency of the grid at a time of rapid change when coal and nuclear are being replaced by renewables and gas.
In contrast to the intermittent generation from wind and solar farms, coal-fired and nuclear power plants provide generation that can be controlled and scheduled (“despatchable power”).
Grid managers have been grappling with this problem of increasing intermittency for almost a decade as wind and solar farms provide an increasing share of generation on the grid (and behind-the-meter at customers’ own premises).
One solution has been to couple wind and solar farms with more generation from natural gas to act as a back-up in case of a drop in renewable output.
Like coal and nuclear, gas generation is despatchable. In fact, gas is even more valuable for grid controllers because output can be ramped up and down very quickly.
Other solutions to intermittency include more long-distance power transmission capacity, more grid-scale electricity storage, and more flexibility in both supply and demand from capacity markets.
Coal and nuclear traditionally provided “baseload” power on the grid but it is not clear whether this concept remains relevant in a grid with growing wind, solar and gas generation.
But the increasing share of gas-fired generation on the grid has led to concerns about the increasing integration of the nation’s gas and electricity systems and their vulnerability to a combined disruption.
In the event of a major supply or demand disruption to the country’s gas supplies, there could be a knock-on effect on electricity production.
The unplanned coupling of systems originally meant to be independent has often been identified as a threat to resiliency (“Brittle power: energy strategy for national security”, Lovins, 1982).
Tightly interconnected and coupled systems are vulnerable to catastrophic and widespread failure (“Normal accidents: living with high risk technologies”, Perrow, 1984).
Electricity regulators have identified a significant risk from growing reliance on natural gas for such a large share of power generation.
There have already been documented instances when gas-fired power plants were unable to operate at full capacity owing to shortages of gas.
In February 2011, extreme cold led to rolling blackouts and gas supply curtailments in the U.S. Southwest with up to 4.4 million electricity customers at some point over three days.
During the Polar Vortex in January 2014, when extreme cold weather swept down through the eastern United States, 35 GW of capacity failed to respond to an urgent order from grid controllers for flat-out generation.
In some cases, gas-fired generators were unable to respond because they could not secure enough fuel at a time when gas demand was also being stretched by extremely low temperatures.
In other cases, equipment froze, which was more of a problem at coal-fired power plants because of their greater age and number of mechanical parts (“Polar vortex review”, NERC, Sept, 2014).
Gas-fired power plants represented 40 percent of the capacity on the grid but 55 percent of the forced outages during the vortex.
Coal-fired power plants accounted for 31 percent of capacity but only 26 percent of forced outages. Nuclear was 12 percent of capacity but just 3 percent of outages.
The February 2011 and January 2014 problems resulted in extensive “lessons learned” exercises by FERC and both the gas and electricity industries.
“Unlike coal and fuel oil, natural gas is not typically stored on site. As a result, real‐time delivery of natural gas through a network of pipelines and bulk gas storage is critical to support electric generators,” the North American Electricity Reliability Corporation wrote afterwards.
“Natural gas is widely used outside the power sector, and the demand from other sectors - particularly coincident end-user gas peak demand during cold winter weather - critically affects gas providers’ ability to deliver interruptible transportation service in the power sector.”
The post-event review recommended the electricity industry work closely with gas suppliers to develop a more effective plan to ensure that sufficient fuel would be available in future cold weather.
Perry’s instruction to FERC has waded into the centre of this debate about reliability and resiliency with a plan clearly designed to help its supporters in the coal and nuclear industries.
The Trump administration has pledged to prevent what it terms “premature” closure of coal and nuclear generating plants.
The proposed regulation is designed to increase payments to coal and nuclear plants to enable more of them to remain open.
There is no doubt the increasing integration of the gas and electricity systems poses a threat to reliability and resiliency.
The question is whether that risk could and should have been dealt with through the normal industry regulatory processes and market incentives.
Or whether the scale and serious nature of the problem justified direct intervention from the secretary, and whether the proposed regulation is the best way to address the issues.
“Integrated approach needed to U.S. electricity policy”, Reuters, Nov. 2014
“U.S. power grid survived polar vortex, but only just”, Reuters, Oct. 2014 (Editing by Mark Potter)