The D.C. Circuit Court of Appeals on Friday denied the Arkansas Public Service Commission’s request that it review a 2016 FERC order directing Entergy Arkansas to continue sharing settlement proceeds under the Entergy System Agreement (16-1305).
FERC approved Entergy Arkansas’ withdrawal from the agreement in 2009. In 2016, FERC held that the utility must continue to share the proceeds of its predeparture settlement with Union Pacific with the system’s other member companies (ER13-432).
The PSC contended that the commission’s order to share the settlement benefits and its method of allocating the benefits was unlawful and unsupported by substantial evidence.
The D.C. Circuit concluded that FERC had a lawful basis to order the sharing of the benefits and was “reasoned” in its allocation methodology.
The PSC pointed to Entergy Arkansas’ withdrawal proceeding in arguing that FERC’s order “essentially amounts to the imposition of an unlawful exit fee or post-withdrawal continuing obligation.”
Writing for the three-judge panel, Senior Circuit Judge David Sentelle rejected the argument, saying FERC was right to conclude “that sharing the Union Pacific settlement benefits was necessary under the principles of equity and was not a penalty or recompense for the company’s exit from the system.”
The court also disagreed with the PSC’s contention that FERC violated the filed rate doctrine by ordering Entergy Arkansas to share the settlement benefits. Under that doctrine, public utilities may only charge rates filed with FERC.
Sentelle said FERC had determined it was not overriding a filed rate, “but merely effectuating the purpose of a non-jurisdictional contract.” He noted Entergy Services was a party to the settlement, and that “FERC found [Services] entered into the settlement on behalf of all the operating companies while they were under FERC’s jurisdiction through the system agreement.”
The court also agreed with FERC’s use of its allocation method, noting the commission found it likely “Entergy Arkansas would have entered into a multiyear transportation contract in 2011 and not benefited from [a] price dip in 2012” without the Union Pacific settlement.
“There was no evidence that Entergy Arkansas could have anticipated the 2012 drop in coal transportation prices and made different contracting decisions,” Sentelle said.
The proceeding stemmed from a 2008 settlement in Arkansas state court between Entergy Arkansas, Entergy Services and other parties against Union Pacific. The settlement locked in a below-market rate for rail delivery of coal by extending an Entergy Arkansas contract with Union Pacific to a three-year period ending June 30, 2015.
Under Entergy’s system agreement, which expired in 2016, its operating companies purchased excess energy from their sister companies at cost, incorporating coal transportation as a component. Union Pacific failed to make coal deliveries at one point, leading to the settlement.
Entergy Arkansas passed a portion of the increased coal costs to the other operating companies under the agreement’s service schedule, and also shared its beneficial coal transportation costs under the Union Pacific settlement.
However, the settlement did not address Entergy Arkansas’ impending withdrawal from the agreement, which FERC approved in 2009.
The Louisiana Public Service Commission filed a Section 206 complaint with the commission, arguing that FERC should allocate the Union Pacific settlement benefits as part of the case. The D.C. Circuit eventually upheld the commission’s decision, but it held FERC “must still review the post-withdrawal arrangements.”
The Louisiana commission again raised the Union Pacific issue when Entergy Services filed a post-withdrawal successor plan with FERC. In response, the Arkansas commission and Entergy Services challenged FERC’s authority to order Entergy Arkansas to share the settlement benefits, because the utility was no longer participating in the system agreement.
Following settlement discussions and a hearing, an administrative law judge determined that the settlement benefits should be allocated among the operating companies and adopted an allocation methodology. FERC affirmed the findings in 2016 and ordered Entergy Arkansas to make a compliance filing refunding the settlement benefits to its sister companies.
FERC and the U.S. Department of Justice struck a blow against opponents of state subsidies for nuclear plants on Tuesday when they jointly filed a brief urging the 7th U.S. Circuit Court of Appeals to reject the argument that Illinois’ zero-emission credit program is pre-empted by the Federal Power Act.
But an analyst for an industry law firm believes the brief, which was quickly cross-filed by Exelon in a similar case in New York before the 2nd Circuit, has a deeper meaning: Leave this to us.
“FERC made clear that ‘we have jurisdiction under the Federal Power Act to deal with what we view as states subsidizing these generation facilities,’” Jennifer Mersing of Stoel Rives told RTO Insider. “I think FERC was saying essentially, ‘We are handling this. … Let us be the forum where this gets worked out.’ They didn’t tip their hand about how they would rule … but I think that FERC is trying to keep within its court how it’s going to deal with states subsidizing certain nuclear facilities.”
The Electric Power Supply Association and retail ratepayers asked the courts to overturn district court rulings last year that dismissed challenges to the states’ ZEC programs. They argued that the state laws were stripping FERC of its authority over the sale of wholesale energy. (See Ill. ZECs Defenders Face Harsh Questioning on Appeal.)
“The Illinois program is not pre-empted,” FERC and the Justice Department said. “It does not require participation in FERC-jurisdictional wholesale auctions as a precondition to receive ZECs. Rather, the Illinois ZEC is ‘targeted’ at an attribute of generation resources over which Illinois has regulatory authority. … The object of the subsidy is the ‘participant,’ not the ‘actual wholesale transaction.’ The district court thus properly concluded that the ZEC program ‘falls within Illinois’ reserved authority over generation facilities.’”
Exelon, which owns five nuclear facilities that stand to benefit from the laws, joined the states in their defense and lauded the brief’s filing.
Exelon’s Clinton nuclear facility, which benefits from Illinois’ zero-emissions credit program. | Nuclear Regulatory Commission
“The U.S. Department of Justice and Federal Energy Regulatory Commission told the courts that states are free to favor clean nuclear energy over pollution-emitting energy from coal, oil and natural gas power plants,” the company said in a statement. “We remain confident that the courts will uphold the view of policymakers and regulators who support the continued operation of Illinois’ nuclear plants and the environmental benefits they provide for consumers.”
Mersing agreed the brief would likely tip the court’s decision in favor of the states and leave FERC to address the issue. Judges in the Illinois case had previously questioned why EPSA was bringing the issue to them when they were simultaneously pleading their case with FERC, which noted in its brief that it will address complaints pending on the issue.
“It’s hard to quantify … but I think that if you have the agency in charge of regulating wholesale power sales [saying it] doesn’t view this law as being pre-empted by the statute it’s in charge of enforcing, I think that’s going to weigh heavily,” Mersing said. “I think the court was probably waiting for FERC to weigh in, so I would expect a decision would come sooner, but we can’t predict when the court will act.”
She predicted the courts will likely uphold the laws, making it unlikely the Supreme Court would take up the case if EPSA were to continue its appeal. The decisions will likely signal other states to pursue similar nuclear subsidies but keep them funneled through FERC, she said.
“You’ll see more states following the path because it removes some legal challenges, but it also depends on how FERC decides to handle the programs,” she said. “I think you’re going to see more complaints at the FERC level versus the federal court level.”
EPSA has requested permission to respond to the brief by June 9, which Exelon has opposed.
The 30-minute event occurred at the Jackson Road substation in American Electric Power’s transmission zone, west of South Bend, Ind. PJM’s Adam Keech explained that a transformer and a transmission line unexpectedly tripped out of service about 1:20 p.m., creating a load on the facility above its ratings.
As part of its response procedures, PJM simulated the effect on the system of losing that facility. The RTO’s procedures call for continuing that analysis for facilities that subsequently would become overloaded and simulating their loss as well. If that continues for five steps without mitigation, or if it hits a larger issue and can’t be resolved, PJM pre-emptively sheds load “before anything else tripped that would potentially create a cascading outage,” Keech said during a special Markets Implementation Committee meeting Friday on updating the variable resource requirement curve.
For this situation, grid operators ordered a reduction of 71 MW of load, he said. However, the transformer kicked back into service, “so the total requested amount was never actually shed … because the equipment came back that quickly.”
No demand response was called, Keech said. PJM later confirmed the actual load shed was 21 MW.
The situation triggered the first performance assessment interval (PAI) under the CP capacity construct, which analyzes the performance of generators that were paid for a capacity commitment to supply power in that region. Units that outperformed their commitments are eligible to receive bonus payments, while those that underperform receive stiff financial penalties. The analysis compares the supply needed to the units that have commitments and only includes units that were able to help by raising their output, Keech said.
PJM is limited in how much information it can release, he said, because the event affected only a small number of generation owners. The RTO’s confidentiality rules restrict what information staff can release if fewer than four generation owners were affected, he said.
Keech noted that some stakeholders expressed concerns with how the incident was communicated and said staff plan to revise procedures to address them.
“I think when we envisioned PAIs, the discrete, very localized load-shed event wasn’t on everybody’s mind. But now that we’ve got it, we should learn to handle it a little bit better,” he said.
The event will have implications for several other markets and reliability calculations, including the balancing ratio and default market seller offer cap. (See “Balancing Ratio,” PJM Market Implementation Committee Briefs: May 2, 2018.)
California regulators last week authorized the state’s investor-owned utilities to recover $738 million for electric vehicle charging infrastructure to help meet the state’s greenhouse gas reduction goals.
The California Public Utilities Commission’s Thursday order stemmed from its 2016 directive ordering the IOUs to propose projects that would advance the electrification of transportation. During the proceeding, the state’s Office of Ratepayer Advocates and The Utility Reform Network negotiated aspects of the program, originally proposed at $1 billion by the utilities.
“The only way to get to a largely carbon-free California is by substantially electrifying the state’s vast transportation system,” Commissioner Carla Peterman said. “The decision made today aims to balance costs with benefits for all ratepayers, considers impacts on competition, and directs significant portions of the utility programs to disadvantaged communities often hit hardest by traffic and air pollution.”
The Natural Resources Defense Council supported the CPUC’s decision, saying it “marks the nation’s single largest investment by the electric industry to eat away at Big Oil’s longtime monopoly over transportation fuels.”
Each IOU had its own package approved by the commission.
San Diego Gas & Electric: A $137 million rebate program for 60,000 Level 2 home-based charging stations, and an EV-only variable hourly energy rate.
Pacific Gas and Electric: $22 million for a “Direct Current Fast Charging Make-Ready Program” supporting 234 fast-charging stations at 52 sites. Also approved was make-ready infrastructure at a minimum of 700 sites to support the electrification of at least 6,500 medium- or heavy-duty vehicles.
Southern California Edison: $343 million to install the make-ready infrastructure at a minimum of 870 sites to support the electrification of at least 8,490 medium- or heavy-duty vehicles, and three new time-of-use rates for commercial customers with electric vehicles.
Make-ready infrastructure includes service connection and supply infrastructure to support EV charging. It is composed of the electrical infrastructure from the distribution circuit to the stub of the EV charging station and can include equipment on the utility side, such as a transformer, or on the customer side, such as electrical paneling or wiring of the meter, the CPUC said.
The commission modified some of the budgets and terms of the program. For example, it rejected SDG&E’s proposal to include existing EV customers in its program. TURN had argued that existing EV customers would be free riders, pointing to a survey that indicated 76% of California EV drivers have income of $100,000 or more. The commission included provisions for disadvantaged communities, setting rebates and adoption targets for EVs in those areas.
The CPUC approved EV charger plans for the state’s three investor-owned utilities
California’s Clean Energy and Pollution Reduction Act of 2015 set new greenhouse gas reduction goals and directed the CPUC to work with other agencies to advance the electrification of transportation.
The CPUC began the proceeding in July 2017 and conducted 11 days of hearings last fall. Other parties included environmental groups, the California Transit Association, Union of Concerned Scientists, EV infrastructure companies and consumer groups.
The decision came just after the California Energy Commission issued a report saying the state will need between 229,000 and 279,000 EV chargers at locations other than single-family homes by 2025 to meet the state’s goals for adoption of zero-emission vehicles. (See California to Require Sharp EV Charger Growth by 2025.)
American Electric Power’s massive Wind Catcher Energy Connection project in the Oklahoma Panhandle continues to rack up regulatory wins.
On Wednesday, independent transmission company GridLiance and Tri-County Electric Cooperative announced they have joined a settlement agreement with AEP related to the company’s proposed 2-GW, $4.5 billion project.
Meanwhile, a Texas administrative law judge has issued a proposed decision approving AEP’s application before the state’s Public Utility Commission. The PUC will take up the proceeding at its July 12 open meeting (Docket No. 47461).
Under the settlement’s terms, GridLiance subsidiary South Central MCN will have the option to construct, own and operate any additional Wind Catcher interconnections in Tri-County’s panhandle service territory of Cimarron, Texas and Beaver counties. The agreement will also provide protections guaranteeing that AEP subsidiary Public Service Company of Oklahoma (PSO) will not provide retail service in Tri-County’s certified service territory for 25 years after the project begins commercial operation.
South Central and Tri-County, along with the Oklahoma Municipal Power Authority and Oneta Power, have now joined with Oklahoma Industrial Energy Consumers and Walmart in reaching settlement agreements with PSO on Wind Catcher.
Tri-County Electric Co-Op’s Service Territory | TCEC
The parties are requesting that the Oklahoma Corporation Commission approve the terms of the agreements. PSO said the terms “collectively result in significant customer savings guarantees and increased use of natural gas power” generated in Oklahoma. (The recent agreements include a new power purchase agreement with Oneta for 300 MW of gas-fired energy and capacity beginning in 2022.)
Dallas-based GridLiance said agreeing to the settlement will allow it to “adequately plan and operate its existing transmission system and future interconnections for the benefit of its utility partners.” Those partners included Tri-County, which will also retain the right to serve retail electric load in its service area.
The co-op’s CEO, Zac Perkins, said the right to serve retail load will last for the life of the Wind Catcher project.
“By partnering with GridLiance on this settlement, we were able to secure the rights to defend the service territory of our retail customers,” Perkins said.
GridLiance CEO Calvin Crowder said the company was pleased with the settlement.
“The panhandle’s economic development depends on a reliable local transmission system that serves multiple needs, and GridLiance remains committed to serving those needs now and in the future,” he said.
GridLiance, which focuses on collaborating with public power entities, entered into an agreement with Tri-County in 2015 to plan, construct and operate transmission infrastructure projects in the panhandle. (See GridLiance Makes First Acquisitions.)
PSO CEO Stuart Solomon said in a release that the agreements further demonstrate that Wind Catcher is good for customers.
“The agreements guarantee customers will save money and allow us to move forward with our plan to increase use of Oklahoma-based renewable energy and natural gas generation to provide affordable, reliable service to our customers,” he said.
PSO is seeking regulatory preapproval to recover $1.36 billion in project costs. It has proposed to the OCC that it cap project costs at 103%, and it has guaranteed the project would qualify for 100% of federal production tax credits available when Invenergy began construction in 2016.
Wind Catcher would consist of an Invenergy-developed wind farm containing 800 2.5-MW turbines. A 360-mile, 765-kV line from the panhandle to Tulsa will connect the wind farm to PSO’s grid and that of sister company Southwestern Electric Power Co., which owns 70% of the project.
AEP’s Wind Catcher site | Invenergy
AEP says Wind Catcher will result in $7 billion in energy savings for its utility customers in Arkansas, Louisiana, Oklahoma and Texas. The Arkansas Public Service Commission has already approved the project, but it still awaits regulatory OKs in the other three states.
SWEPCO has filed an application before the Texas PUC to amend its certificate of convenience and necessity and authorize its interest in Wind Catcher, and for preapproval of various ratemaking treatments to recover the project costs. The utility estimates its share of the costs at approximately $3.2 billion, with $1.1 billion within Texas retail jurisdiction.
In recommending the project’s approval, Texas ALJ Henry Card relied on the precedent set by the commission’s recent approval of Southwestern Public Service’s wind farm in West Texas. In that proceeding, the commissioners overcame their concerns that SPS was requesting 478 MW of energy when it already had sufficient capacity on its system to meet demand. (See Texas PUC Issues Final Order for SPS Wind Farm.)
“Utilities may obtain a CCN for general economic purposes not just when there is an increase in demand necessitating additional generation,” Card said in his decision.
FOLSOM, Calif. — CAISO is going back to the drawing board to overhaul its reliability-must-run program, switching to a “holistic” approach after a more narrowly crafted backstop procurement proposal was rejected by FERC last month.
The ISO said it will combine into one process what was previously two separate phases of RMR rule changes. It hopes to develop its new proposal and complete a stakeholder process in time for presentation to its Board of Governors in March 2019.
“We’re not really talking about phases any more; this is really one big initiative,” CAISO Infrastructure and Regulatory Policy Manager Keith Johnson said during a stakeholder meeting Wednesday. Many stakeholders had previously urged CAISO to combine the two phases and tackle what are perceived to be wider problems with the RMR construct, but the ISO had favored a more incremental approach.
As out-of-market payments, RMRs have stirred controversy among ISO participants and prompted a larger debate about resource adequacy in California and whether current policies are appropriately incentivizing needed generation. Most recently, CAISO issued a May 15 market notice saying it will seek RMR designations for NRG Energy’s Ellwood and Ormond Beach units, which the company in March said it planned to retire. (See CAISO: New 2019 RMR Contracts Possible.) Environmental groups had cheered the news of the retirements.
FERC last month rejected CAISO’s proposal to make substantive changes to the separate but related Capacity Procurement Mechanism, which is similar to RMR in that it functions as a backstop to financially support needed generation. In its decision, the commission said the ISO needs to propose a more comprehensive package of reform for CPM. (See FERC Rejects CAISO CPM Proposal.)
The RMR program is used as a reliability tool when a generating unit wants to retire but is still needed for reliability. RMR participation is mandatory, and units receive payments based on their cost of service, while those units designated under the CPM participate on a voluntary basis and receive a capped market-based price. The ISO said it is not currently planning to merge the two processes.
Among the items being considered in the newly crafted RMR reform package are:
Modifying compensation for both RMR and CPM;
Subjecting RMR units to a must-offer requirement in the wholesale market;
Providing flexible RA credits from RMR units; and
Modifying cost allocation of CPM to reflect load migration.
Other goals include lowering banking costs for RMR invoicing, streamlining and automating the RMR settlement process and making interim changes to the pro forma RMR agreement.
Whatever backstop procurement the ISO develops will have to conform to — and interact with — a package of RA reforms being developed by the California Public Utilities Commission. At the CPUC, the ISO is advocating enhancements to flexible RA capacity procurement requirements, establishing multiyear RA procurement and vetting appropriate load forecasting assumptions.
“The ISO does think the RA program could be refreshed,” Johnson said.
CAISO has said it is likely the RMR reforms will need to go to settlement. During Wednesday’s meeting, stakeholders discussed how to negotiate the terms of an agreement without having to go through a settlement process at FERC after the proposal is filed.
Mark Smith, vice president of government and regulatory affairs at Calpine, called for an increase in the scope of proceeding to include revising the RMR pro forma agreement, modifying transmission planning to prevent backstop procurement and other reforms.
“We have a difference of opinion from the ISO as to what defines holistic,” Smith said during a presentation.
Eric Little, manager of wholesale markets at Southern California Edison, said that RMR and CPM have become replacements for resources normally provided by RA. He also mentioned a must-offer requirement for RMR/CPM resources and said they should receive cost-based contracts plus a reasonable return.
“In addition, the compensation method that was once a trade-off of competitive market for capacity augmented by energy market rents will need to be made equivalent under a contract mechanism with the CAISO,” Little said during a presentation.
The ISO is also working on increasing transparency around retirements, saying it will drop confidentiality provisions around notices of retirement or mothballing of units to ensure market participants are aware. That change, which will only require a revision to the ISO’s generator management business practices manual rather than approval by the board, is due to be implemented by July 1.
CAISO plans to issue a new RMR straw proposal by June 26, with another stakeholder meeting July 11 to discuss the many complex issues around what will be a major change in its procurement policies.
FERC on Tuesday opened an investigation to determine whether the cost recovery for a Cleco Power gas-fired plant that serves as a MISO system support resource unit in southern Louisiana is justifiable.
The commission accepted and suspended a Cleco rate schedule that allots a fixed monthly payment of $1.7 million for the continued operation of the 338-MW Teche Power Station Unit 3, and directed its chief administrative law judge to decide whether to initiate a hearing over the matter (ER18-1237).
MISO first won approval for the plant to operate under an SSR in mid-2017 after Cleco signaled that it intended to retire the unit. (See MISO Wins OK for Cleco Plant SSR.) At the time, the RTO said the Teche plant was needed to prevent severe thermal violations on its transmission system that could not be addressed until the Terrebonne-Bayou Vista 230-kV line could be put into service this year. Entergy now expects the line to be placed into service in early 2019.
Cleco’s Teche Power Station in Baldwin, LA | Google
In May, FERC granted MISO approval to renew the SSR agreement through March 31, 2019. The agreement provides for both hourly compensation of the plant and the fixed monthly charge, which Cleco says covers costs not included in hourly compensation and fully reimburses it for the costs of operating and maintaining the unit. Cleco had already included the associated $1.7 million in monthly payments in its rate schedule filed with FERC in March.
Entergy protested the rate schedule, saying Cleco failed “to provide enough information to establish that the proposed monthly payments are just and reasonable.” Entergy contended that Cleco’s filing failed to contain “many of the details” required by FERC regulations to allow the commission and interested parties to assess the validity of the costs associated with the agreement.
Cleco has contended that the compensation for its second SSR agreement “is just and reasonable and is no more than necessary to maintain the availability of Teche 3.”
Entergy also contested Cleco’s request for a waiver of the 60-day notice requirement, which would allow the proposed rate schedule to become effective April 1. In its Tuesday ruling setting the Teche matter for hearing, the commission rejected Entergy’s argument, saying its previous rulings have held that nothing in the SSR program would require a generator to shoulder uncompensated costs.
“Here, the record indicates that Teche 3 has been providing reliability service pursuant to the second SSR agreement since April 1, 2017,” the commission said. “Thus, it is appropriate that Cleco be made whole for the costs that it incurs while providing SSR service.”
MISO and PJM plan to unveil rule changes late this summer that will better synchronize how they manage incremental auction revenue rights (IARRs) along their seam.
Speaking during a May 30 Joint and Common Market meeting, PJM Senior Market Simulation Analyst Brian Chmielewski said the RTOs are working to clarify and improve their current IARR coordination process, particularly where it concerns PJM’s customer-funded options.
Both RTOs offer IARRs, which represent additional auction revenue rights created by transmission upgrades that increase capability on their transmission facilities. IARR megawatts are awarded for the additional capability created for the life of the upgrade or 30 years, whichever is less, and valued each year based on annual financial transmission rights auction clearing prices.
However, PJM’s process provides an additional option that allows a specified IARR to be awarded when a customer agrees to fund transmission upgrades necessary to support the new ARR request.
MISO and PJM coordinate studies of IARR requests when there is a potential impact on flowgates operated by either RTO, but they say there are gaps in the current process designed to coordinate IARRs between them.
Chmielewski said the RTOs need to ensure they are properly transferring firm flow entitlements on the impacted flowgates of an IARR to make sure FTR revenue remains adequate. Because PJM is also obligated to guarantee at least 80% of IARR megawatts, the RTO may have to require “some guarantee” from MISO on future firm flow entitlement allocations, Chmielewski said.
Chmielewski also said all of PJM’s capabilities from upgrades might not be reflected in firm flow entitlement allocation between the two RTOs, and that current, non-active flowgates that could be activated in the future may impact the viability of IARRs.
The RTOs said they’ve met for several discussions on the issue since November and will present proposed revisions at the Aug. 29 JCM meeting.
Chmielewski said MISO and PJM could unveil joint operating agreement revisions by November, with a new process rolled out in the first quarter of 2019.
President Trump directed Energy Secretary Rick Perry Friday to force grid operators to provide a lifeline to struggling coal and nuclear plants, saying their retirements threaten national security.
The Department of Energy had not issued an order as of Friday afternoon. But a 40-page draft memo described as an “addendum” includes a reference to the order and describes the department’s legal foundation, saying the closures threaten military bases and the nation’s nuclear workforce. The memo was first reported by Bloomberg, which said it was prepared for a Friday meeting of the National Security Council.
The memo said DOE would be directing RTOs and ISOs “to purchase or arrange the purchase of electric energy or electric generation capacity from a designated list of Subject Generation Facilities (SGFs) sufficient to forestall any further actions toward retirement, decommissioning or deactivation” for 24 months — the time it said the department and its and National Laboratories will need to identify “Critical Defense Facilities” served by “Defense Critical Electric Infrastructure (DCEI).”
“To identity DCEI facilities, additional analysis will be required to gain a more detailed understanding of location-specific security vulnerabilities in our energy delivery systems, including the interdependencies associated with electric generation and transmission, and natural gas and petroleum pipelines, as well as their supply chains,” the memo said. “In the meantime, DOE’s order provides a temporary stop-gap measure to prevent the further permanent loss of the fuel-secure electric generation capacity for the grid upon which our national security depends.”
DOE said it also is directing SGFs outside RTO/ISO territories “to continue generation and delivery of electric energy according to their existing or recent contractual arrangements with load-serving entities.” The draft did not identify the generators that would benefit from the order.
The president’s long-awaited and highly controversial action was announced by Press Secretary Sarah Huckabee Sanders. “Unfortunately, impending retirements of fuel-secure power facilities are leading to a rapid depletion of a critical part of our nation’s energy mix and impacting the resilience of our power grid,” Sanders said in a statement. “President Trump has directed Secretary of Energy Rick Perry to prepare immediate steps to stop the loss of these resources and looks forward to his recommendations.”
It is the administration’s second bid for a coal and nuclear bailout. In January, FERC rejected Perry’s Notice of Proposed Rulemaking to subsidize coal and nuclear plants with onsite fuel. The commission instead initiated a rulemaking on grid resilience (AD18-7). (See Don’t Rush on Resilience, Commenters Urge.)
‘Tipping Point’
DOE warns of a “tipping point” in the loss of “fuel-secure” generation, citing the retirements of 59 GW of coal capacity between 2002 and 2016, the loss of 15 nuclear plants since 1990 and announced retirements of 12 nuclear units representing 11 GW.
It cites a 2008 Defense Science Board report that concluded Defense Department installations are “99% dependent on the commercial power grid.”
In addition to the purported risk to DOD facilities, the memo also cited the need for a “robust civilian nuclear industry” to support the “entire U.S. nuclear enterprise — weapons, naval propulsion, nonproliferation, enrichment, fuel services and negotiations with international partners.”
“Without a strong domestic nuclear power industry, the U.S. will not only lose the energy security and grid resilience benefits but will also lose its workforce technical expertise, supply chain and position of clean energy leadership,” it said.
DOE said it supports FERC’s actions, including its opening of the resilience docket in January, but that “too little progress has been made, while the risk of high-impact events, especially those caused by intentional attacks, continues to grow.”
“Given the need to safeguard the existence of fuel-secure generation facilities to promote our national defense and to maximize domestic energy supplies, DOE is compelled to exercise its authorities to avert a serious supply disruption in the wake of a natural disaster, an adversarial attack or some combination of the foregoing.”
It quotes from a 2017 NERC report that said increased “reliance on natural gas exposes electric generation to fuel supply and delivery vulnerabilities” and that “premature retirements of fuel-secure baseload generating stations reduces resilience to fuel supply disruptions.”
It also cites NERC’s November 2017 report on potential disruptions to the natural gas system, which noted that some regions rely on gas for more than 60% of their peak electric demand.
DOE also cites the threat of cyberattacks on the grid, saying, “To avoid and recover from blackouts, it is essential that the system have adequate generation and transmission capacity broadly dispersed.” It notes that only nuclear generators maintain “the kinds of ‘guns, guards and gates’ and other physical and cyber-hardening measures that would be needed in the event of a major attack.”
Legal Challenges Likely
Observers Friday differed over whether the administration’s action will survive almost certain legal challenges.
In rebuffing Perry’s NOPR in January, FERC said DOE had failed to show that existing RTO tariffs were unjust and unreasonable under Section 206 of the Federal Power Act.
The DOE memo claims different legal authority, citing the Defense Production Act of 1950 (DPA) and Section 202c of the FPA, which allows the energy secretary to issue emergency orders during shortages of electric energy, facilities or fuel.
The memo cited DPA Section 101c, which gives the secretary authority to issue orders based on findings that energy supplies “are scarce, critical and essential” and needed for “maintenance of energy facilities [and] cannot reasonably be accomplished without exercising [this] authority.”
DOE said the legislative history of Section 202c shows that “Congress contemplated the use of the provision not merely to react to actual disasters, but to act in a preventive manner. A variety of man-made and natural threat conditions require … a federal agency ready to do all that can be done in order to prevent a breakdown in electric supply.”
The department says it has deployed FPA Section 202c on eight occasions. However, those were in response to regional energy challenges; it has not previously been applied nationwide.
During the Western Energy Crisis in late 2000, DOE issued an order to ensure gas supplies to Pacific Gas and Electric, then on the verge of bankruptcy. In several instances, the department has ordered temporary interconnections to provide supplies to regions following blackouts or natural disasters, including hurricanes Katrina and Rita.
The law was invoked on three prior occasions to require operation of generation facilities to prevent energy or reactive power shortages.
In 2005, DOE granted the D.C. Public Service Commission’s request to order Mirant Corp. to continue running its Potomac River Generating Station despite its inability to meet EPA’s National Ambient Air Quality Standards, finding that the region otherwise faces a “reasonable possibility” of extended blackouts.
Most recently, DOE granted PJM’s request to order Dominion Energy Virginia to continue running its Yorktown Power Station despite its violation of EPA’s Mercury and Air Toxics Standards, finding reliability could be at risk during summer peaks.
Yorktown Generating Station | Dominion
To minimize conflicts with environmental regulations, DOE noted, it limited its orders to having the generators serve only as backup power if other sources were unavailable.
ClearView Energy Partners analyst Christine Tezak noted in a bulletin to clients Friday that the DPA gives DOE “significant authority to determine and respond to national security impairments, even in peacetime, and thus far the courts have been reluctant to intervene.”
“Unless and until critics marshal counterarguments to the concerns DOE has presented in [its] memo, we will continue to assign low probabilities to successful judicial intervention or reversal,” she added.
Rabeha Kamaluddin, a partner at Dorsey & Whitney, predicted in an interview that the courts will reject DOE’s claim that the subsidies are justified by 202c. But, she said, “you can expect anything in today’s political landscape.” DOE “may have a leg to stand on” using the DPA in combination with the FPA, she added.
“Combining [202c with] the DPA provides more room for DOE to make creative legal arguments,” said Ari Peskoe, director of the Electricity Law Initiative at Harvard. “It’s still far from clear that the proposal would be upheld by a court.”
“There is no grid emergency that justifies this,” tweeted Joel B. Eisen, law professor at the Richmond School of Law. “Nor does the combo of two laws, neither of which is appropriate in its own right, add any further support.”
“202c gives pricing authority to FERC,” said Avi Zevin of the New York University School of Law’s Institute for Policy Integrity. “FERC has already said market rates are sufficient to meet reliability and resilience. So, I’m still not clear how we get around that even when you add DPA into the mix.”
FERC’s role in implementing the order is unclear. While 1977 amendments to the FPA transferred the emergency declaration authority under 202c to the energy secretary from the Federal Power Commission — FERC’s predecessor — the commission still has dominion over rates under FPA Sections 205 and 206, Kamaluddin said.
FERC declined to comment.
Bailout Costs
The bailouts could cost from $311 million to $900 million annually in PJM, ISO-NE, NYISO and MISO alone, according to Energy Innovation Policy & Technology, which supports policies reducing greenhouse gas emissions. The low estimate represents the out-of-market payments needed to bring units with negative net cash flows up to zero. The upper limit adds capital recovery and a rate of return on undepreciated capital and future capital expenditures.
The group compiled the estimates based on the rejected DOE resilience NOPR. “There are, of course, important differences between the resilience NOPR and the 202c actions being discussed by the Trump administration, but our study is a good rough estimate of the cost to keep the same group of uneconomic plants online,” said Robbie Orvis, director of energy policy design for the group.
More than 80% of the coal subsidies would go to five companies (NRG Energy, Dynegy, FirstEnergy, American Electric Power and Talen Energy), while 90% of the nuclear price supports would go to five companies (Exelon, Entergy, Public Service Enterprise Group, NextEra Energy and FirstEnergy), the group said.
Industry Reaction
The renewable energy and natural gas industries united with consumer groups to condemn the bailout. Representatives of 10 trade groups — Advanced Energy Economy, the American Council on Renewable Energy, American Petroleum Institute, American Wind Energy Association, Business Council for Sustainable Energy, Electricity Consumers Resources Council, Electric Power Supply Association, Energy Storage Association, Natural Gas Supply Association and Solar Energy Industries Association — released a joint statement calling the move an unprecedented overreach that would distort competitive markets.
“There was no emergency when coal and nuclear interests sought federal relief, and there is none today that justifies such unprecedented executive branch intervention in the economic life of the country,” EPSA CEO John Shelk said.
“The administration’s plan to federalize the electric power system is an exercise in crony capitalism,” said Malcolm Woolf, AEE senior vice president of policy.
John P. Hughes, CEO of the Electricity Consumers Resource Council, which represents industrial consumers, said the threats cited are “phony” and that the costs could cripple U.S. manufacturers. “The federal government should not use the pretext of ‘national security’ to pick winners and losers in the energy markets, and it must certainly not treat U.S. manufacturing jobs as inferior to the jobs at uneconomic power plants,” he said.
The American Coalition for Clean Coal Electricity praised the action, noting that “almost 40% of the nation’s coal fleet has shut down or is expected to close.”
PJM said Friday that the grid is “more reliable than ever,” and that its recently announced fuel security initiative will ensure grid resilience without upsetting its markets. (See PJM Seeks to Have Market Value Fuel Security.)
“Any federal intervention in the market to order customers to buy electricity from specific power plants would be damaging to the markets and therefore costly to consumers. There is no need for any such drastic action.”
In response to an inquiry, ISO-NE spokeswoman Marcia Blomberg said “it’s too early to comment on a draft proposal that has just been revealed.”
“MISO is monitoring the reports of the potential Department of Energy action along with our ISO/RTO counterparts,” spokesman Mark Brown said. “At this time, we have seen no official communication from DOE.”
Other grid operators did not respond to requests for comment. DOE and NERC also did not respond to inquiries.
Requests from Murray Energy, FirstEnergy
Although Trump promised during his campaign to end the “war on coal” and put miners back to work, the Sierra Club says retirements have continued unabated since he took office. “In the first two months of 2018, we’ve already retired more coal that we did in three of the Obama years, and we’re on track for our second biggest year of coal retirements ever,” the group said in March.
Coal mining chief executive Robert Murray and FirstEnergy, his company’s biggest customer, have lobbied relentlessly for subsidies. (See Photos Show Murray’s Role in Perry Coal NOPR.) FirstEnergy asked Perry to invoke 202c in a letter in March. (See FES Seeks Bankruptcy, DOE Emergency Order.) FirstEnergy lobbyist Jeff Miller, who ran Perry’s unsuccessful 2016 presidential campaign, reportedly made the case to Trump over dinner in April.
Exelon, the nation’s largest nuclear generator, has largely focused its lobbying efforts on winning state subsidies for endangered reactors.
Despite news of the administration’s action, Exelon saw shares drop 1% Friday, while FirstEnergy was down 0.6% on the day.
Shares of mining company Peabody Energy rose 4.6%, while Arch Coal was up 2%.
NYISO said Wednesday it is prepared to meet peak demand this summer, with a total of 42,169 MW of power resources available to cover an expected peak of 32,904 MW — 2.9% above the long-term average.
Demand last summer peaked at 29,699 MW on July 19, coming in 7% below the 10-year average of 31,968 MW. New York set its record peak of 33,956 MW at the end of a week-long heat wave in July 2013.
NERC standards mandate that each ISO/RTO secure enough day-ahead capacity to meet the single largest contingency. The ISO’s summer capacity assessment used a “deterministic approach” to approximate capacity margins and operating reserves for baseline and extreme weather conditions, according to Wes Yeoman, NYISO vice president of operations. The assessment uses a set of projected derates based on five-year Equivalent Forced Outage Rate demand averages.
At baseline peak weather conditions, the ISO forecasts 1,599 MW of capacity margin surplus, which is above the baseline peak load, plus 2,620 MW of required operating reserves. The baseline peak forecast is up 1,214 MW over last year’s forecast.
| NYISO
For the 90th percentile forecast of extreme weather conditions, the ISO projects a capacity margin shortfall of 241 MW, an increase of 1,683 MW over last year’s extreme weather forecast.
The ISO reported 39,325 MW of generating capacity available from power plants in New York and 1,219 MW of demand response resources plus another 1,625 MW available from neighboring regions.
“Based on historical performance, the net resources projected to be available to serve during the summer peak total 37,123 MW,” said the report.
New York’s 2018 operating reserve requirement of 2,620 MW is based on the potential loss of the system’s largest single resource. Peak demand combined with operating reserves translate into a total capacity requirement of 35,524 MW.
