By Rich Heidorn Jr.

FERC received more than 300 comments on Energy Secretary Rick Perry’s proposed “resiliency” rulemaking by its Monday deadline, with coal and nuclear interests backing the idea and RTO officials and most other stakeholders roundly rejecting it (RM18-1).

The flood of comments was so heavy that it taxed FERC’s filing system, causing the commission to announce late in the afternoon it would accept comments into Tuesday.

Perry’s Notice of Proposed Rulemaking would require FERC-jurisdictional RTOs and ISOs with capacity markets and day-ahead and real-time energy markets to ensure “full cost recovery” for any generation that can provide “essential energy and ancillary services” and has 90 days of fuel supply on site. Units subject to cost-of-service rate regulation would be excluded.

In its request for comments on the NOPR, FERC asked stakeholders to weigh in on more than 30 questions. Few commenters bothered. But they were effusive in their support — and withering in their criticism.

Those that depend on coal and nuclear generation, including labor unions, shippers and mining companies, heartily endorsed it.

The rule “will produce numerous benefits for all Americans by preserving the continuing viability of critical coal-fired power plants,” said the Kentucky Coal Association (KCA), which represents 120 companies in the No. 4 coal-producing state. “This will not only support a more reliable and resilient power grid but will also have a profound and positive impact in Kentucky and across America by preserving jobs and economic development.”

The Nuclear Energy Institute embraced the cost-of-service compensation as a temporary measure “at least until other market structures are put in place that appropriately value the resiliency attributes that nuclear generation units provide.”

The natural gas, solar and wind industries joined with the Electric Power Supply Association and other industry groups to blast the proposal as “a transparent attempt to prop up uneconomic generation … that is not otherwise needed for reliability.”

RTO officials and their Market Monitors uniformly rejected the idea, with the ISO/RTO Council saying “the negative consequences of the NOPR … are obvious.” PJM, ISO-NE and NYISO also filed their own comments in opposition. (See related story, RTOs Reject NOPR; Say Fuel Risks Exaggerated.)

A bipartisan group of eight former FERC commissioners also blasted the proposal as a repudiation of 25 years of progress toward competitive markets.

Amory Lovins, cofounder of the Rocky Mountain Institute, derided Perry’s proposal as employing “language urgent without evidence, alarmist without cause, and peremptory without authority.”

Given the widespread opposition from all but the coal and nuclear industry — and the myriad questions about how the proposal would be implemented — it appears highly unlikely the commission will act to approve it on the accelerated schedule Perry had demanded, or that it would survive the almost certain legal challenges if it did so.

Perry directed FERC to complete a final rule within 60 days after publication of the NOPR in the Federal Register. The commission, an independent agency, is not required to approve the plan or follow his timeline. (See FERC’s Independence to be Tested by DOE NOPR.)

Below, based on a review of more than 50 comments as of press time, is a summary of the feedback FERC received. Reply comments are due Nov. 7.

Is the Grid at Risk?

Perry said the rule was needed to ensure sufficient supplies of “essential reliability services,” which NERC has defined as including voltage support, frequency services, operating reserves and reactive power. Just and reasonable rates for such generators would cover “its fully allocated costs and a fair return on equity,” including operating and fuel expenses and the costs of capital and debt, the NOPR said.

KCA cited “the clear findings in the proposed rule that the nation’s grid is at risk and that rule-secure resources are indispensable.”

“The commission simply cannot carry out its mission without adopting rules that appropriately value fuel-secure generating facilities that are capable of producing electricity when fuel supplies are interrupted or unavailable,” it said.

The Utility Workers Union of America (UWUA) cited a PJM analysis that it said concluded that “even moderate retirements” of coal and nuclear plants “would reduce PJM’s fuel assurance capability by almost 30% if the units were replaced by natural gas.”

“The country is at a crossroads, and urgent commission action is required before the value provided by critical baseload generation capacity is lost forever,” the American Coalition for Clean Coal Electricity (ACCCE) and the National Mining Association said in a joint 64-page filing.

“We should not allow short-term prices to dictate significant changes in our generation fleet that will reduce the nation’s resource diversity and grid resiliency,” argued NEI, which said nuclear generation units have the highest capacity factors of all generating resource types. “Because of these attributes, nuclear power plants provide reliable baseload generation that stabilizes the grid and moderates price volatility.”

The EPSA filing countered by citing a Rhodium Group analysis that concluded “0.00007% of customer-hours lost to outages were caused by fuel supply emergencies between 2012-2016, a period when 32% of the country’s coal fired power units and 6% of its nuclear generating units were retired. The same period also featured two of the coldest winters during the past 30 years in the Eastern United States, including the 2014 polar vortex.

“The vast majority of electric service disruptions in the United States are related to distribution or transmission outages, not unscheduled generation outages,” they continued. “And virtually all of the customer-hours that were lost due to fuel supply disruption between 2012-2016 were related to a single incident involving one coal plant in Northern Minnesota.”

David Patton, whose company performs market monitoring in MISO, NYISO and ISO-NE, acknowledged “there may be fuel supply contingencies or other contingencies that have not been fully considered by RTO planners or [NERC].” But he said, “To turn immediately to an out-of-market compensation scheme without considering the alternatives for addressing these issues through the RTO planning and market framework is both inefficient and ultimately unreasonable.”

Will the Proposal Help Resiliency/Reliability?

Many commenters said the proposal would harm rather than help reliability.

“The NOPR proposal would provide compensation to particular units that may otherwise retire because they are older, less efficient and less reliable than newer units,” the IRC said. “Supplanting newer, efficient units with older, less reliable ones in the markets will threaten reliability and market efficiency. This problem will be exacerbated because the NOPR does not outline any minimum performance standards or criteria for determining whether eligible resources are situated in an optimal location to support future reliability needs (including, particularly local reliability and voltage needs).”

Due to rule changes implemented since the 2014 polar vortex, the council said, “ISO-NE, NYISO and PJM have ably maintained reliability in their respective regions.”

Is there a compensation problem?

Longview Power, operator of a five-year-old, 700-MW supercritical coal-fired plant near Morgantown, W.Va., which claims to be “North America’s most efficient coal fired generator,” said it has been undercompensated in the PJM market.

CEO Jeffery L. Keffer said the plant — which has a heat rate of 8,842 Btu/kWh, a 92% availability factor and emissions at least 70% lower than the U.S. coal fleet — is dispatched by PJM as a baseload unit whenever it is available and been awarded capacity payments through the 2020/21 delivery year. It also receives payments for reactive power and other ancillary services.

“However, the compensation paid to Longview for its reliability contributions and ancillary services is wholly inadequate. During 2016, when Longview’s equivalent availability factor was over 92%, it received an average energy payment of only $27.50/MWh. Similarly, the 2017 average energy price paid to Longview is expected to be $28.63/MWh.”

Patton said, however, that the proposal to guarantee full cost recovery of resources “that may be economic to retire will likely generate costs that vastly exceed any reasonable estimate of” the value of lost load. He questioned the notion that coal units were being forced into “early” retirement, noting that the average age of existing coal-fired plants in 2016 was 38 years, within the 35-50-year life span for those assets.

Impact on Wholesale Markets

Critics said Perry’s call for “full cost recovery” for coal and nuclear units would reverse 25 years of competitive wholesale markets.

The R Street Institute, which promote free markets and limited government, praised the NOPR’s call for market improvements such as improving pricing for reliability and resiliency services. “But the detailed problem statement, factual foundation and proposed policy remedies of the NOPR are inconsistent with empirical evidence and principles of wholesale electricity market design,” said Devin Hartman, electricity policy manager. “Motivations for market reforms should never aim to adjust compensation with a predetermined result — in this case preventing certain power plants from retiring. The rationale for markets is to let competitive forces determine resource allocations, which lowers costs and better manages risk than a pre-determined, centrally planned approach would.”

“Proper valuation of coal baseload generation does not require the commission to abandon or ‘blow up’ the competitive electric markets,” KCA insisted. “KCA and other supporters of a resilient grid and affordable baseload power are simply requesting that the commission ensure that competitive market based rules fairly compensate the benefits of baseload generation sources, which are the most cost-effective way to meet constant electrical demand so as to provide for just and reasonable rates to consumers and generators.”

“Valuing coal and nuclear [electric generating unit] resiliency benefits is consistent with market evolution,” wrote UWUA President D. Michael Langford. “Electricity market constructs can be modified — as they are so frequently to accommodate a variety of purposes — to efficiently operate while compensating for reliability services.”

A bipartisan group of eight former FERC commissioners — including former Chairs Elizabeth Anne (Betsy) Moler, James Hoecker, Pat Wood III, Joseph T. Kelliher and Jon Wellinghoff — filed joint comments saying that Perry’s proposal would be “a significant step backward from the commission’s long and bipartisan evolution to transparent, open, competitive wholesale markets.”

“The commission’s adoption of the published proposal would instead disrupt decades of substantial investment made in the modern electric power system, raise costs for customers and do so in a manner directly counter to the commission’s long experience,” they said.

The former commissioners noted their role in issuing Order 888, which established transmission open access, and Order 2000, which defined the responsibilities of RTOs, saying their “shared collaborative mission across party lines and presidential administrations has been a model of good government.” More than two-thirds of U.S. electric customers are now served by competitive wholesale markets.

“Widely diverse interests have invested tens of billions of dollars in both competitive and regulated infrastructure. Customers and the industry have benefited from lower costs and better, more reliable services. Technological innovation has swept the entire value chain.”

They acknowledged that the markets have been impacted by federal tax subsidies for wind and solar generation, as well as “less overt benefits for oil, gas and coal extraction.”

“The commission cannot ignore these interventions, and in fact, should actively inform legislators how such programs impact market operations. But one step the commission has never taken is to create or authorize on its own the kind of subsidy proposed here.”

The IRC said Perry’s proposed cost recovery “stands in stark contrast to other types of narrowly tailored cost recovery mechanisms like reliability-must-run (RMR) mechanisms.”

“The negative consequences of the NOPR proposal are obvious. By affording certain generators guaranteed, full fixed and variable cost recovery for providing some undefined ‘resiliency’ benefit based on an arbitrary ‘fuel-security’ standard, the NOPR will shield eligible generators from the competitive forces that discipline market bidding behavior and ensure that market dispatch and prices are based on least-cost, security-constrained optimization of the resource portfolio.”

Legal Questions

The Harvard Environmental Policy Initiative and Columbia University’s Sabin Center for Climate Change Law said the NOPR is flawed because it doesn’t prove the preliminary conclusion required by the Federal Power Act that current wholesale rates are not just and reasonable.

“This glaring omission dooms DOE’s proposal under Section 206 of the Federal Power Act and allows the commission to issue a swift rejection without weighing in on the merits,” Harvard’s Ari Peskoe wrote. “The NOPR’s observation that wholesale markets do not price ‘resiliency’ does not substitute for an explicit proposed finding that current rates are unjust and unreasonable. DOE does not define ‘resiliency,’ nor has the commission ever used that word in connection with wholesale rates. DOE’s bare assertion that rates do not account for undefined attributes does not provide adequate notice necessary for meaningful public comments.”

Justin Gundlach, staff attorney for the Sabin Center, agreed. “The commission should recognize [the proposal] as a politically motivated gambit to allocate resources to the support of coal- and nuclear-fired generating capacity,” he said.
The IRC said the proposed requirement that RTOs submit compliance 15 days after the effective date of the final rule — 45 days after the rule is published — “is unreasonable and contrary both to commission policy and past practices.”

The IRC said “the NOPR proposes a drastic redesign of existing competitive market structures but provides very little implementation details and no discussion about acceptable cost allocation for the proposal. Given the dearth of specificity in the NOPR, parties will be left guessing as to what might be an acceptable compliance proposal until such time as the final rule is issued. Giving only 45 days from that point will deny RTOs and ISOs adequate time to craft compliant policies and develop tariff revisions. Equally significantly, a 45-day window from issuance of the final rule to submission of compliance filings provides very little time for RTOs and ISOs to initiate stakeholder discussions, let alone time for the RTOs and ISOs to consider what are very likely to be highly disparate stakeholder views on the RTO/ISO’s compliance proposal.”

ACCCE and NMA asked FERC to find existing RTO tariffs unjust and unreasonable. “It is critical that the commission make such a finding, and direct RTOs and ISOs to modify their tariffs to ensure that existing coal-fired generators are able to fully recover their operating costs,” they said.

The EPSA group filing said the proposal would “provide discriminatory compensation” to coal and nuclear generators. “The justification for the proposed payments – resiliency – is not well defined, nor does the DOE NOPR demonstrate that resiliency is lacking in the aforementioned regions,” they said.

It was filed by 20 stakeholders, including the Advanced Energy Economy and trade groups representing competing fuels and alternate resources (American Biogas Council, American Council on Renewable Energy, American Forest & Paper Association, American Petroleum Institute, American Wind Energy Association, Energy Storage Association, Natural Gas Supply Association and the Solar Energy Industries Association).

“This is what a very bad proposal can do,” tweeted EPSA Senior Vice President Nancy Bagot. “Bring people together to save the electricity market!”

90-Day Fuel Supply

DOE would require a generator receiving “resilience” payments to have a 90-day fuel supply “enabling it to operate during an emergency, extreme weather conditions, or a natural or man-made disaster.”

But commenters said the requirement is arbitrary.

Longview said it keeps 10 to 30 days of coal on hand. “Whether dealing with an extreme weather event, such as a ‘polar vortex’ or a terrorist attack, we see the likelihood of the event extending for 90 days as highly unlikely and particularly unprecedented. An event of this length would likely involve serious damage to the transmission grid, which means electric deliverability, not fuel supply, would be the limiting factor in supplying electricity to end users.”

Monitor Patton said the 90-day supply requirement was indefensible, saying he is unaware of any credible contingency that would support the requirement. “Major pipeline repairs have generally been completed within a few weeks; extreme weather conditions typically last from three to 10 days. … On-site fuel supplies of oil or LNG can often be resupplied within a few weeks,” he said. “To the extent MISO has had long-duration fuel-security issues, the issues have been with coal supply limitations due to railway congestion. … Not one of [the large-scale outages since 1965] was impacted by lack of long-term fuel security.”

Patton also dismissed the NOPR’s effort to tie its concern to “the devastation from Superstorm Sandy and Hurricanes Harvey, Irma and Maria.”

“In general, hurricanes are more likely to damage distribution and transmission systems and cause flooding at power stations, impacting resource types in specific locations rather than certain fuel types,” he said. “In other words, these contingencies will generally affect all resources is certain areas, regardless of fuel type, even the resources that qualify as resilience resources under the NOPR.”

Industry Groups’ Response

The Natural Gas Supply Association said there is “no basis” for the NOPR and its proposed solutions. It said “no fuel source is failsafe,” and that natural gas is a “reliability asset for the power sector,” saying interstate pipelines delivered 99.79% of firm contractual commitments over the last 10 years.

WIRES, a transmission trade group, said it would oppose any FERC action that “retreats from the market-oriented and technology-neutral regulatory policies that the commission has fostered for a quarter century [or] fails to fully acknowledge the central role that development of robust electric transmission infrastructure must also play in any effort to make the grid more reliable and resilient.”

The Edison Electric Institute asked FERC to clarify whether the rule changes would include only the Eastern RTOs or also CAISO and SPP, which have no capacity markets.

It said the commission “should institute an appropriate process to investigate potential issues related to resilience”
and direct the Eastern RTOs “to evaluate what, if any, steps need to be taken within their markets to define the specific resource attributes and essential reliability services that may need to be valued in their market(s) and whether alternate compensation mechanisms are needed consistent with the market structure in the region.”

Independent power producers were uniformly opposed, with filings by the New England Power Generators Association (NEPGA), the Independent Power Producers Of New York (IPPNY), PJM Public Power Providers and the Independent Power Producers of Ohio, Pennsylvania and West Virginia.

“New England and New York have long histories of developing market mechanisms to meet reliability,” NEPGA and IPPNY said in joint comments.

“PJM has demonstrated that it will make modifications to the market design to address changing reliability needs of customers,” said the IPPs from Pennsylvania, Ohio and West Virginia, citing the Capacity Performance rules enacted after the 2014 polar vortex. “In a perverse irony, the NOPR will likely harm grid reliability by chasing away the very innovation and investment in new generation needed to maintain the long-term integrity of the grid.”

Customers’ Response

The Industrial Energy Consumers of America said the proposal would raise costs for electric-intensive manufacturers, estimating a 1-cent increase in industrial electricity rates would increase its members’ costs by $9 billion to $10 billion annually. “As a large stakeholder who consumes 26% of U.S. electricity and spends approximately $65 billion on electricity each year, the manufacturing sector is very concerned about this rule,” said IECA President Paul Cicio.

In a joint filing, the Industrial Energy Consumers of Pennsylvania and the Pennsylvania Manufacturers Association
said the rule “threatens to dramatically change the economic climate in Pennsylvania by increasing electric prices and undermining the numerous and relatively recent benefits being generated by the booming and prospering Pennsylvania shale gas industry.”

The group noted that Pennsylvania consumers paid more than $12 billion in stranded costs to utilities in its transition to competition. “For many years after the legislation, the wholesale market prices were higher than those that the utilities used to calculate their stranded cost claims. The generation owners kept those additional profits.”

The Kentucky Industrial Utility Customers took no position on whether the proposal should be adopted, but said if it is, FERC should consider a separate capacity market for grid reliability and resiliency resources. It also said the authorized return on equity “should be the minimum necessary to ensure that the fuel-secure generation does not retire prematurely. An ROE in the 2 to 4% range would accomplish that. Any positive return is better than losing money. If the ROE is set too high, then the affected merchant generators would have reduced incentive to seek a more permanent market-based solution.”

Rule Defenders’ Script

Coal state politicians, such as Republican Sen. Shelley Moore Capito and fellow members of the West Virginia congressional delegation, weighed in with support.

The proposal also found some unlikely defenders, such as the Cleveland branch of the NAACP, which said “the continued operation of the baseload coal and nuclear power plants translates into safer and more prosperous communities.”

Several of the coal industry interests — including Camelot Coal, FreightCar America, Campbell Transportation and IBEW Local 50 — included identical language in their comments: “The preservation of certain plants will avoid the need to replace lost generation with imports and the associated construction of infrastructure to facilitate such importation. … Premature plant closures will deplete the stable of highly skilled (and specifically trained and experienced) employees, many of whom have lived in the region for several years and who take great pride in their work. … The baseload generation facilities that may be retired prematurely offer stability and optionality.”

Many of them raised the threat of layoffs and lost tax revenue from plant closures.

The Utility Workers Union of America, which represents 50,000 electric, gas, water and nuclear industry workers nationwide, focused on the potential impact in Avon Lake, Ohio, where it said closure of a coal plant would result in reduced income and property taxes. A city councilman told Congress in 2012 that the plant’s closure would force a 50% cut in the city’s emergency medical service operating budget and a $4 million cut — 11% — for the local school district, forcing it to cut programs for special needs students.

Michael Kuser, Amanda Durish Cook, Tom Kleckner, Jason Fordney and Rory D. Sweeney contributed to this article.