Page 1100 – RTO Insider

May 8, 2020

PJM, IMM Present MOPR Rules for State Procurements

PJM and its Independent Market Monitor on Wednesday shared with stakeholders their proposals for responding to FERC’s April 16 directive that state default service auctions be considered state subsidies and subject to the minimum offer price rule (MOPR).

The straw proposals are attempting to address Paragraph 386 of FERC’s rehearing order, which said that state procurement auctions are a form of a state subsidy because they provide a payment or other financial benefit to capacity resources that are part of a state-sponsored or state-mandated process.

PJM IMM MOPR — Chen Lu, PJM | © *RTO Insider*

PJM attorney Chen Lu presented the RTO’s “potential compliance approach” during a special session of the Market Implementation Committee on Wednesday.

The commission on April 16 rejected rehearing of its June 2018 order declaring PJM’s capacity market unjust and unreasonable (EL16-49-001, et al.) and virtually all of its December 2019 ruling spelling out the expanded MOPR while providing clarification on several points (EL16-49-002, et al.). PJM presented its initial response to the orders at the April 30 Markets and Reliability Committee meeting. (See PJM Outlines Revised MOPR Compliance Filing.)

Opponents of the expanded MOPR wasted no time in petitioning the 7th Circuit Court of Appeals and the D.C. Circuit Court of Appeals to review the orders. (See Stakeholders Appeal Expansion of PJM MOPR.) On Tuesday, the U.S. Judicial Panel on Multidistrict Litigation consolidated the five petitions and assigned the case to the 7th Circuit in Chicago (Case 07/1:20-ca-01645).

While the appeals are pending, PJM is required to make a new compliance filing by June 1.

To comply with FERC’s directive, Lu said PJM plans to amend its March compliance filing by removing state default procurements as an exception from the definition of a state subsidy.

“We recognize there are several implementation challenges with this rule given that state auctions are generally brought after PJM’s capacity auctions, and also the fact that the entities that bid in state procurement auctions do not necessarily participate in PJM’s capacity market,” Lu said. Revenues from state procurements may not be traceable to specific capacity resources, he added.

PJM Straw Proposal Approach

Lu said the proposal attempts to comply with the rehearing order while preserving “normal commercial activity” associated with the state procurements.

PJM’s proposal includes default service auctions in the definition of a state subsidy but excludes certain voluntary bilateral transactions from the definition where there’s no clear linkage between the revenues from a state default procurement auction and a capacity resource.

Lu said any capacity resource that has a clear link to revenue from a state default procurement auction would be subject to the MOPR under the proposal. Included would be:

a capacity resource that directly clears or intends to clear in a state default procurement auction;
any state-directed, long-term bilateral transaction between a default retail service provider and an owner of the capacity resource; and
long-term transactions between a default retail service provider and an “affiliated owner” of the capacity resource in which the transaction is unit-specific or “not at prevailing market rates.”

Chen also laid out the types of transactions that would not be triggered by the MOPR:

Transactions of one year or less between a default retail service provider and the owner of the capacity resource. These transactions are not designed to support the development, construction or operation of a resource.
Long-term transactions between a default retail service provider and an “unaffiliated owner” of the capacity resource so long as the transaction is not directed by a state.
Long-term transactions between a default retail service provider and an “affiliated owner” of the capacity resource where the transaction is not unit-specific, is at prevailing market rates and is not directed by a state.

Sam Randazzo, chairman of the Public Utilities Commission of Ohio, asked Lu how the “prevailing market rate” would be calculated if a default auction is for an unspecified quantity and an unspecified time.

Lu said prevailing market rates could be demonstrated by showing the price was consistent with either the generally available price to all buyers or other competitive supply bids at the time of the auction. Lu said PJM recognizes state auctions typically happen after the capacity auctions have occurred, so auction participants would have to obtain documentation of sales in the event PJM or the Monitor seeks to review bids.

Randazzo said Ohio’s auction is managed by an independent auction manager who, as part of the process, reviews all the bids and makes sure that the structure of the auction and its outcome are competitive. The lowest bid is picked on the recommendation of the auction manager, he said, creating a structure that ensures the outcome is competitive and consistent with prevailing prices. He said it will be much more difficult to come up with a market price after the fact for a capacity product that is unique and dynamic.

“What you’re creating is something that’s going to subject the results of these auctions to hindsight analysis,” Randazzo said. “It’s going to reduce the number of suppliers and increase the cost of the product itself.”

Jason Barker of Exelon said he also fears reduced liquidity in the state provider of last resort (POLR) auctions could result in less competitiveness and higher prices. He said it is impractical for PJM to try to determine a specific generator source for every megawatt that marketers use to fulfill their winning POLR supply offers.

“Marketers hedge with market products at different points in time,” Barker said. “It is fruitless to go behind the POLR auction to try to paint the megawatts that the suppliers use to hedge. PJM could quickly implicate every generator that sells power.”

IMM Alternative

Monitor Joe Bowring presented an alternative proposal to PJM’s straw proposal. Bowring said compliance with Paragraph 386 should be the simplest method that conforms with FERC’s intent and to minimize the impact on state auctions, given that intent.

PJM Monitor Joe Bowring | © *RTO Insider*

Bowring said that regardless of how PJM or stakeholders feel about the impacts of Paragraph 386 and whether it should have been included in FERC’s determination, the best way to move forward was a narrow interpretation. Otherwise, he said, it could result in a much wider interpretation of the MOPR than was intended by the commission.

In the IMM proposal, resources used to meet a load-serving entity’s retail auction obligations would not be subject to the MOPR if the resources are purchased at market rates. Bowring said the IMM defines market rates as “the forward curve for energy for the time period of the retail auction obligation, with a basis adjustment to the zone.”

Bowring said that market rates would also include the PJM capacity market price for the applicable delivery year and locational deliverability area, and PJM ancillary service market prices.

Resources subject to the MOPR would be those already under it and those sold above market rates, Bowring said. The MOPR would also apply to any resource sold to LSEs participating in a retail auction to meet any state-mandated requirements, including renewable energy credits, zero-emission credits, offshore renewable energy credits or any other mandate that limits participating capacity by technology, fuel, location or other attributes.

“The intent is to be as light-handed as possible while still attempting to meet what we interpret to be the commission’s intent,” Bowring said.

May 7, 2020February 18, 2025

Western EIM Governing Body Hears COVID-19 Updates

The coronavirus pandemic has curtailed demand for electricity and made it challenging for new entities to go live with the Western Energy Imbalance Market, but two recent activations went well despite the awkward timing, the EIM’s Governing Body heard Wednesday.

Governing Body members were also briefed on EIM benefits and the impending departure of a member of the EIM’s Body of State Regulators (BOSR).

On April 1, Arizona’s Salt River Project (SRP) and Seattle City Light both went live with the EIM, joining the interstate real-time trading market’s nine other active participants while many of their employees were working remotely.

“Since then, both entities have been operating smoothly in the market,” said Petar Ristanovic, CAISO vice president of technology. In a slide, he wrote, “This was the smoothest EIM activation so far. Both entities were well prepared and their personnel trained so they were passing all hourly tests from the start.”

Salt River Project power lines traverse the desert near Tempe, Ariz. | © RTO Insider

COVID-19 has kept most CAISO workers at home, too, while control room staff have been isolated from others and separated by crews into two control rooms, one at CAISO’s Folsom headquarters and the other in its secondary control room in the nearby town of Lincoln, General Counsel Roger Collanton told Governing Body members. The ISO also set up a “virtual control room” in Folsom to use, for instance, when the main control room needs to be cleaned, Collanton said.

CAISO hasn’t experienced any significant problems during the pandemic, he said. “We’ve seen no grid reliability issues, and we’re not predicting any at this time.”

CAISO compared expected loads without California’s stay-at-home order and actual loads with the order in place, Collanton said. Weekday loads were down by about 7.5% during peak-demand times and down 5% during off-peak times. Weekend load reductions were less — 3% during peak demand and 1% off-peak.

Energy prices were down by 26% in the day-ahead market and 30% in the real-time market, he said.

Benefits Heading Toward $1 Billion

Mark Rothleder, CAISO’s vice president for market policy and performance, said the EIM saw “robust” member benefits of nearly $58 million during the first quarter of 2020, bringing the EIM’s total benefits since its start in 2014 to almost $920 million.

SRP and Seattle City Light have already begun seeing benefits from joining the EIM, Rothleder and utility representatives said.

EIM benefits to date | CAISO

The market is on course to accumulate $1 billion in benefits later this year, he said. The benefits often come from buying and selling excess renewable energy.

“We’re seeing continued benefits and tracking well,” Rothleder said. “In fact, we’re probably tracking toward $1 billion in benefits since the start of the EIM — I’m estimating probably in the third quarter of this year.”

White Joining WECC

In a briefing from the EIM’s BOSR, Chair Letha Tawney, with the Oregon Public Utility Commission, announced that Commissioner Jordan White, a familiar figure in Western energy circles, will be leaving the BOSR and resigning from the Utah Public Service Commission effective May 20.

“He’ll be joining WECC [also headquartered in Salt Lake City], so he’s not going far, both literally and figuratively,” she said. “But we will miss him. He is an engaged and effective member of the BOSR.”

EIM Governing Body member Valerie Fong | EIM

WECC, the Western Electricity Coordinating Council, announced May 1 that White will be filling a newly created role as vice president of strategic engagement and deputy general counsel.

White served in multiple roles in the EIM, both as chair of the BOSR just prior to Tawney’s term and as a current member of the Governing Body’s nominating committee.

“For those of you who’ve worked with him and know him personally, he’s just very enjoyable and easy to work with and really brings a thoughtful perspective to the conversation,” Tawney said. “We will wish him all the best in his new role.”

Utah PSC Chair Thad LeVar will represent Utah on the BOSR after White’s departure. Other BOSR members have started the process to replace White on the EIM nominating committee. “We’re hoping to have that done by May 20,” she said.

May 7, 2020

COVID-19 Takes Bite out of AEP’s Q1 Earnings

Count American Electric Power — one of the nation’s premier electric utilities — among those companies whose environment has been turned upside down by the COVID-19 coronavirus.

The utility on Wednesday repor t ed first-quarter earnings of $495 million ($1.00/share), down 13.5% from 2019’s opening quarter earnings results of $573 million ($1.16/share). The company said revenue fell almost 10% to $3.7 billion, and electricity sales were off 12% during the quarter.

Wall Street reacted to the news on Wednesday by trading AEP’s share price down 5.5% from Tuesday’s close to $78.82. The company’s stock has lost nearly a quarter of its value since hitting an all-time high of $104.97 on Feb. 18 as the COVID-19 outbreak was heating up.

“When there is a pandemic like the one we’re experiencing today that has not occurred in 100 years, and this nation’s economy has been effectively shut down for months, there is no question that everyone is challenged and AEP is no exception,” CEO Nick Akins said during a conference call with financial analysts.

AEP is forecasting an overall 3.4% decline in sales this year. | *AEP*

The second quarter has not been much better. Akins said new data indicates total April sales were down 4.3% from a year ago, with 10% and 7.7% drops in industrial and commercial sales, respectively, which more than offset a 6% increase in residential activity.

The Columbus, Ohio-based company has reaffirmed its 2020 operating earnings guidance range of $4.25 to $4.45/share and its 5% to 7% long-term growth rate. However, management expects to be in the lower half of its guidance, due to revised load assumptions related to COVID-19.

“Regardless of whether we forecast a V-shape, a U-shape or W-shape COVID-19 recovery,” Akins said, “we see our service territory as an arbitrage between residential load and commercial industrial load that is defined really by a pendulum between the financial characteristics of working from home versus the restart of commercial and industrial businesses.”

Referencing boxer Mike Tyson’s comment that “everyone has a plan until they get punched in the mouth,” Akins said, “Yes, we’ve been challenged a little bit, but we are very much still in the match.”

AEP’s North Central Wind Energy project is still on schedule. | *AEP*

To counteract the loss of sales, AEP has cut planned operations and maintenance expense by $100 million and shifting $500 million of its planned 2020 capital spending into future years. Akins said the company still plans to invest $33 billion over the next five years.

The future capital investment does not include AEP’s $2 billion North Central Wind Project, comprised of three wind farms in Oklahoma that will produce 1.49 GW of capacity to consumers in the company’s Oklahoma and Louisiana service territories. The project has received regulatory approval in Arkansas and Oklahoma and from FERC, but Louisiana and Texas have yet to weigh in.

Akins said the regulatory proceedings are on schedule and the project is moving forward. “That was the importance of Arkansas’ approval,” he said, noting that the state can increase its megawatt allocation should another Southwestern Electric Power Company state reject the application.

May 7, 2020November 30, 2023

Exelon Bid to Keep Mystic Units Running Provokes Outrage

When Exelon announced that it would retire its 2,001-MW Mystic Generating Station, ISO-NE was forced to amend its Tariff and sign an expensive and controversial out-of-market contract to keep the plant running through May 2024 for reliability.

Now, Exelon has filed interconnection requests to keep the two combined cycle units at the plant in Everett, Mass., running beyond the end of its $400 million cost-of-service agreement for “fuel security” in 2024. Exelon’s April 20 filing with ISO-NE asked the RTO to treat the two gas-fired units — with combined capacity of 1,600 MW in summer and 1,700 MW in winter — as “new” resources.

“The filing preserves an additional option for Mystic 8 and 9 to provide unique fuel security and electric reliability benefits to the region following the cost-of-service period, if ISO-NE decides that it does not need Mystic 8 and 9 in the market for transmission security for at least one more year,” Exelon Generation spokesman Mark Rodgers explained in response to questions from RTO Insider.

News of Exelon’s change of heart provoked outrage among some stakeholders.

“Exelon is looking to keep the Mystic units in the market after holding the region hostage for millions of dollars in pursuit of short-term financial gain,” Katie Dykes, commissioner of the Connecticut Department of Energy and Environmental Protection, told RTO Insider.

“Exelon’s 2018 retirement announcement sought to exploit fuel security weaknesses in the region revealed by ISO New England’s Operational Fuel-Security Analysis. Since then, the continuing failure of ISO-NE to timely address fuel security and recognize, rather than negate, state policies continues to expose our ratepayers to bald exercises of market power today,” Dykes said.

Exelon’s filing “appears to be a cynical ploy premised upon two inherent failings of ISO New England,” said Greg Cunningham, director of Conservation Law Foundation’s Clean Energy and Climate Change program.

“The first failing is to clear not much other than natural gas power plants in its forward capacity auctions. And the other is the risk that it mismanages this RFP for transmission that will provide for an alternative to Mystic,” he said, referring to ISO-NE’s first-ever competitive transmission solicitation, issued in December.

“This absurd result is entirely avoidable,” Cunningham said. “If it manages this RFP well, ISO-NE can select projects that simultaneously address New England’s clear public policy desire for clean resources, while avoiding a dinosaur of a plant like this coming back like a phoenix out of the ashes.”

No Gaming Allowed

“Under the ISO-NE Tariff, the rules are clear that the current Mystic generation must retire once the reliability needs are addressed,” said Theodore Paradise, senior vice president of transmission strategy for Anbaric Development Partners. “Those rules were directed to be put in place by FERC to prevent gaming — seeking the higher of cost-of-service or market prices.”

If the Mystic units try to lock in another high-priced contract triggered by their retirement announcement, that would “continue the injury to New England ratepayers already incurred by the astonishingly high annual cost-of-service agreement to keep both the plant and the LNG terminal,” Paradise said.

“Mystic had its chance and made its decision for an economically challenged plant,” he said. “Exelon has put in the binding retirement request and those uneconomic, rate-inflating fossil units are going to be closed soon. Because of the lack of a gas supply situation, new LNG units at the site don’t make sense economically at current energy and capacity prices.”

Uneconomical

Exelon two years ago said it would retire Mystic as uneconomical, given the plant’s dependence on LNG that costs more than natural gas from pipelines.

The cost-of-service agreement for Mystic Units 8 and 9 and the Exelon-owned LNG terminal that supplies them is scheduled to expire in May 2024. The agreement pays Exelon an annual fixed revenue requirement of almost $219 million for capacity commitment period 2022/23 and nearly $187 million for 2023/24, subject to true-ups for fuel costs.

ISO-NE initially asked FERC to waive Tariff provisions to prevent the retirement because of the region’s fuel-security reliability challenges in winter. FERC rejected the request, ordering the RTO to amend its Tariff — which then allowed cost-of-service agreements only to address local transmission security issues — to now allow such contracts for fuel security issues. The commission also ordered the RTO to develop market-based solutions to address fuel security, setting off a two-year effort that culminated with the RTO’s filing of its Energy Security Improvements (ESI) market design on April 15. Exelon filed its interconnection request five days later.

FCA 15

Exelon’s mention of providing “fuel security” had some observers scratching their heads, considering the RTO’s assertion at the April New England Power Pool Reliability Committee meeting regarding FCA 15, the auction that will be held next year for capacity year 2024/25.

ISO-NE presen t ed the RC with its initial inputs to the fuel security reliability review, which indicate that no resources that submitted a retirement delist bid for FCA 15 or were previously retained for fuel security will be retained for fuel security for the period. (See “FCA 15 Fuel Security Reliability Review” in NEPOOL Reliability Committee Briefs: A pril 22, 2020.)

But maintaining interconnection access would allow Exelon to extend Mystic’s stop-gap role if there were delays to either the planned transmission upgrades or the approval and implementation of ESI. ISO-NE asked FERC to approve ESI effective Nov. 1, 2020.

Exelon also would face an obstacle from the commission’s requirement in its December 2018 order accepting the Mystic agreement that it include a “clawback” mechanism.

The order said that if Mystic re-entered the market after the agreement ends rather than retiring, Exelon would have to refund to the RTO “all costs, less depreciation, for repairs and capital expenditures that were needed to continue operation” of Mystic during the agreement (ER 1 8-1639). The commission said the clawback “will not apply if ISO-NE chooses to extend the agreement.”

The commission disputed Mystic’s contention that cost-of-service agreements used for fuel security purposes merit different clawback treatment than those for transmission. “We disagree. At the end of a cost-of-service agreement’s term, the need for the unit to provide relief for a transmission constraint would be replaced by a transmission upgrade,” the commission said.

“In this case, the need for cost-of-service treatment for Mystic will have been replaced by a market-based mechanism for fuel security,” the commission said. “Under a market-based mechanism, if Mystic is not the most economic alternative to meet a fuel security need, then Mystic will not be selected to provide capacity and/or fuel security. The clawback mechanism helps place Mystic on similar footing with other resources that would not have benefitted from a cost-of-service agreement in the new market-based mechanism.”

Under ISO-NE’s Tariff, to qualify as a “new” capacity resource, Mystic would have to add 40 MW of capacity over its last summer qualified capacity number or invest at least “$200 per kilowatt of the whole resource’s summer qualified capacity after re-powering … (in base year 2008 dollars).”

RFP

ISO-NE received 36 proposals in response to its December 2019 solicitation to address reliability concerns over Mystic’s retirement, specifically transmission facility overloads under peak load conditions in the Boston area and system restoration concerns with the underground cable system in the area.

The RTO said the proposals ranged from $49 million to $745 million with in-service dates from mid-2023 to 2026. The RTO said it would not disclose proposal details for 175 calendar days (until Aug. 26, 2020), after verifying details in the proposals. The ISO expects to make a final selection in summer 2021. (See ISO-NE Planning Advisory Committee: M arch 18, 2020.)

The only proposal made public so far is one from Anbaric, which announced details for the 900-1,200-MW Mystic Reliability Wind Link pr o ject to bring offshore wind energy interconnecting in southeastern New England to Boston. It includes empty cable conduits for an additional 1,200 MW from offshore wind farms.

Massachusetts Department of Public Utilities Chair Matthew Nelson seemed unconcerned that Mystic might not retire as scheduled, saying the DPU “is encouraged by the ISO-NE competitive process for transmission and continues to be focused on ensuring Massachusetts ratepayers are provided with the most reliable service at the lowest possible cost.”

ESI

The Energy Security Improvements market design will allow ISO-NE to procure energy call options for three new day-ahead ancillary service products to improve the region’s energy security, particularly in winter when natural gas shortages can leave generators without fuel. Option awards will be co-optimized with all energy supply offers and demand bids in the day-ahead market. (See ISO-NE Sending 2 Energy Security P l ans to FERC.)

Based on a related proceeding at FERC in March, Exelon apparently believes that it is now free to pursue a separate cost-of-service agreement based on “transmission security” rather than fuel security.

While all six New England states pay for the cost of a fuel security cost-of-service agreement, the Tariff says the cost of a transmission security agreement for Mystic would be paid by the northeast Massachusetts — or “NEMA” — capacity zone, which includes Boston.

FERC in March rejected Tariff revisions filed jointly by the RTO and the New England Power Pool to clarify that resources retained for fuel security reasons will not be retained for other reasons once the fuel security retention period ends (ER20-8 9). (See FERC Rejects ISO-NE Fuel Securi t y Tariff Revisions.)

Exelon in that proceeding argued that the proposal “unduly discriminates” against fuel security resources in general and the Mystic units in particular. The company contended that “the proposal results in different treatment for transmission security resources based on whether the resource has previously provided fuel security service, despite the fact that transmission security and fuel security resources are similarly situated for purposes of retirement.”

The RTO’s desire to develop a long-term market-based fuel security solution and competitively develop transmission solutions for the Boston area do not constitute substantial evidence that it is just and reasonable to eliminate a reliability safeguard, Exelon said.

In rejecting the revisions, the commission found that “instead of retaining such a resource for transmission security (as it would any other resource that was not previously retained for fuel security), ISO-NE would need to address this issue through either real-time operating procedures, such as shedding load, or through the use of a gap [request for proposals] solicitation.”

May 6, 2020February 19, 2025

DC Circuit Skeptical of NARUC Challenge to FERC Order 841

A three-judge panel of the D.C. Circuit Court of Appeals did not seem particularly convinced Tuesday by state regulators’ and utilities’ arguments that FERC exceeded its jurisdiction when it issued Order 841.

Representing the National Association of Regulatory Utility Commissioners, Jennifer Murphy argued that FERC had violated provisions of the Federal Power Act that protected states’ authority over their local distribution systems with Order 841. Issued in February 2018, the order directed RTOs and ISOs to revise their tariffs to allow energy storage resources full access to their markets. (See FERC Rules to Boost Storage Role in Markets.)

Murphy said NARUC is supportive of the order except for “one small, unnecessary aspect,” in which the commission asserted that states could not prohibit storage resources on the distribution side from selling their power into wholesale markets. Along with Dennis Lane — representing organizations including the American Public Power Association and Edison Electric Institute — Murphy cited FPA Section 201b, which says FERC “shall not have jurisdiction … over facilities used in local distribution.”

Lane said that interconnecting distributed storage to the bulk electric system could require upgrades both to utilities’ distribution and transmission systems. “Our concern as distribution utilities is what adjustments we are going to have to make … to the distribution system to allow [a storage owner] to” sell wholesale power, he said. The distribution system “is assigned exclusively to states” under the FPA.

Judge Merrick Garland cited FERC v. EPSA, in which the Supreme Court overruled the D.C. Circuit and upheld FERC’s jurisdiction over demand response resources through Order 745. The D.C. Circuit had ruled that, because DR was a retail product, it was not subject to federal regulation. (See Supreme Court Upholds FERC Jurisdiction o v er DR.)

But Murphy said 745 allowed states to “opt out” and prevent DR resources from participating in the markets, which the Supreme Court had noted made it in compliance with Section 201b, contrary to the Electric Power Supply Association’s claims. “The issue in the EPSA case was the actual setting of [wholesale rates]; the opt-out happened beforehand, and the courts have said it is only an incidental effect if you’re changing the amount of [what is] participating in the [wholesale] markets,” she said.

AES battery storage | AES

Lane also noted that in EPSA, the Supreme Court had agreed with the D.C. Circuit that FERC could not regulate practices that indirectly affected wholesale rates and had noted that the commission had acknowledged this limitation when it issued 745.

Judge Robert Wilkins said, however, that if the petitioners’ “argument was correct, the opt-out wouldn’t fix the problem, because your argument is essentially that FERC can’t mandate the use of these behind-the-meter storage facilities. … It doesn’t matter if they give the states the ability to opt out of the mandate. Your argument is that they don’t have the power to do that in the first place.”

“Well, Judge Wilkins, I don’t want to sound facetious, but we’re pretty practical people,” Lane said, “and if they did an opt-out, we wouldn’t be raising this issue.”

“Although claiming the ability to negate such state decisions, the commission chose not to do so in recognition of the linkage between wholesale and retail markets and the states’ role in overseeing retail sales,” the Supreme Court wrote in EPSA.

Lane argued that the court had not addressed the question of whether the opt-out clause in 745 was legal under the FPA, only that it belied EPSA’s arguments of infringement on state authority. “We’re asking you now to address this question,” he said.

Standing?

The judges also questioned whether the petitioners had standing in the case. Wilkins noted that no request for rehearing of the order made the argument that Lane had about EPSA. He also noted that none of the petitioners had made the argument that FERC exceeded its authority in their opening briefs. They had only argued that the order adversely affected states’ ability to regulate their distribution systems.

The judges also asked multiple times how states and utilities were harmed by the order, noting that they had not made any claim that they were being forced to meet certain requirements. They also asked why the court should not wait until FERC challenged a state prohibiting a resource from accessing a wholesale market before it decided on the issue.

Garland asked Murphy if any state had laws or rules in place preventing distributed storage resources from selling into the wholesale market. Murphy conceded there were not. Garland also asked both her and FERC attorney Anand Viswanathan if the order usurped state authority to prevent storage resources from interconnecting at all; both said no.

Wilkins also asked if the order mandated that states facilitate storages’ participation in the markets. Viswanathan said, “Absolutely not.”

“The commission clarified throughout the rule that whatever authority states or retail regulators had before the rule to police matters like reliability and safety of the distribution system, none of those authorities are changed as a result of the rule,” Viswanathan said.

The petitioners’ arguments seemed to mirror those in Commissioner Bernard McNamee’s dissent a year ago in Order 841-A, which clarified aspects of but ultimately upheld the original order. McNamee said he would have granted rehearing to reconsider not providing states the ability to opt out of the participation model for storage resources located behind the meter. (See FERC Upholds Electric Storage Order.)

But Viswanathan pointed out that “no one at the commission level made the argument that the commission simply does not have authority to regulate electric storage resources.”

“What [the petitioners] have argued is that even if the commission has the authority over this practice, states still have to consent to it,” he continued. “The problem with that … is because of the limited nature of their challenge, either the commission has the authority over the practice, or it does not. … There’s no suggestion in the statute that the commission’s Federal Power Act authority hinges on states approving” that authority.

Analysis

“In our view, at least two of the three judges at the court appeared skeptical of claims brought by petitioners that FERC exceeded its statutory authority,” ClearView Energy Partners said in a memo. “Therefore, we think the court may uphold the provision, either by rejecting petitioners’ standing or by affirming the provision as within the commission’s exclusive jurisdiction.”

Even if the court agreed with the petitioners, ClearView said, “we do not expect a disruptive change to the opportunities for [storage] to participate in the wholesale markets and potentially earn new revenue streams” because their challenge was only to a narrow aspect.

“The court did not appear headed toward making a broad jurisdictional conclusion that would vacate 841,” Jeff Dennis, general counsel for Advanced Energy Economy, tw e eted. “Seems like the court could either (1) dismiss for lack of standing, saying no state has shown precise harm to its regulation of distribution facilities or (2) find that 841 properly exercises FERC’s authority over wholesale transactions by local storage resources, while leaving to a future case how this exercise of authority interacts with state actions to regulate safety and reliability of distribution facilities.”

May 6, 2020

FERC Extends Deadline in Net Metering Dispute

FERC on Monday extended the deadline for comments in a high-stakes dispute over net metering until June 15 (EL20-42).

The New England Ratepayers Association (NERA) filed a petition for declaratory order on April 14 asking FERC to outlaw net metering for rooftop solar generation by ruling that the commission has exclusive federal jurisdiction over wholesale energy sales from generation sources located on the customer side of the retail meter.

The declaration would require such sales be priced under the Public Utility Regulatory Policies Act of 1978 or the Federal Power Act, which could require the customer to have a rate on file with FERC.

“In other words, the group seeks to end net metering as we know it,” tweeted Ari Peskoe, director of the Electricity Law Initiative at the Harvard Law School Environmental and Energy Law Program.

FERC granted the 30-day extension in response to a request by the National Association of Regulatory Utility Commissioners (NARUC), which cited the coronavirus pandemic and the potential impact of the commission’s ruling in the case.

FERC net metering — FERC extended the deadline to June 15 for comments in a high-stakes dispute that could end net metering.

NARUC said states with full net metering programs treat the entire output of energy from an electricity consumer’s generation source that is located on the same side of the retail meter as the consumer’s load as subject to state jurisdiction.

“NARUC has not yet taken a formal position on this petition; however, many NARUC members have expressed serious concerns with the petition’s timing, scope, jurisdictional implications and implementation challenges,” the organization said in its mo t i on.

NARUC, which had requested an extension until Aug. 12, was supported in its request by several state regulatory commissions, consumer advocates and other intervenors. NERA said it opposed any extension beyond 60 days.

NE R A describes itself as a non-profit advocacy group seeking to protect “families and businesses” from excessive utility rates.

The Energy and Policy Institute, however, say s its “lobbying and regulatory advocacy often align with the interests of investor-owned utilities and the fossil fuel industry” and says it has close ties to New Hampshire’s Gov. Chris Sununu.

NERA’s petition was filed by Steptoe & Johnson attorneys David B. Raskin and Richard L. Roberts and reiterates arguments that Raskin has been making for years. Raskin has represented the Edison Electric Institute in the past, but EEI has said it is not involved with the filing.

Dozens of stakeholders have filed to intervene in the FERC docket thus far, an indication of the stakes in the case.

May 6, 2020

Dominion Energy Earnings Impacted by Weather, Not COVID-19

Dominion Energy saw little load impact from the COVID-19 pandemic in the first quarter, company officials said Tuesday, but earnings were hurt by an abnormally warm winter season.

The company reported a $270 million ($0.34/share) net loss compared with a $680 million net loss ($0.86/share) in the first quarter of 2019.

CFO Jim Chapman said unfavorable weather conditions impacted utility earnings by 9 cents as Virginia recorded its third warmest first quarter on record. The first quarter marked Dominion’s 17th straight quarter of delivering results within the company’s guidance range, which was set at between $1.05 and $1.25/share.

Dominion is initiating a second quarter operating earnings guidance with a range of 75 cents to 85 cents/share, Chapman said, while affirming the annual guidance range of $4.25 to $4.60/share. The second-quarter and full-year guidance ranges reflect preliminary expectations for the impacts of the pandemic.

Dominion officials are assuming that the U.S. economy will begin to ramp up through late summer, and Chapman said electricity demand in Virginia has remained positive in relation to recent years despite the pandemic.

“Virginia load is continuing to prove extremely resilient,” he said, attributing the resilience to several factors.

Residential usage within Dominion Energy Virginia (DEV), which typically accounts for around 45% of revenue, increased in year-over-year volume by about 3% in April as more individuals worked from home.

Despite the stay-at-home order in Virginia, Chapman said commercial load decreased by only 3% in year-over-year volume as losses from shuttered businesses were offset by the “proliferation of data centers in our service territory,” which has accounted for 30% of commercial volume since 2019.

A limited industrial exposure within Dominion’s Virginia footprint also kept load impacts from being severely impacted, he said, with only 6% of DEV’s revenue attributable to industrial usage.

Finally, government and military electricity usage, which accounts for 16% of revenue and 15% of volume, was up almost 4% year-over-year in April.

“Based on observable data, we’re not at present forecasting major COVID-driven revenue impacts associated with reduced load at Dominion Energy Virginia during the remainder of 2020,” Chapman said. “Of course, the situation is dynamic.”

CEO Thomas Farrell said the company has taken steps to help customers struggling in the uncertain economy created by closures because of the pandemic, including voluntarily suspending nonpayment service disconnections and waiving late fees across all utility service territories.

The COVID-19 response within the company has involved utilizing frequently drilled crisis response plans, he said, as well as the activation of its remote connection infrastructure, which is enabling more than half of Dominion’s workforce to operate remotely.

Farrell said Dominion has been fortunate that, among its 19,000 employees in 20 states of operation, “very few” workers have tested positive for COVID-19. Most of the positive cases are asymptomatic or mildly symptomatic, and most of them have already returned to work.

A Renewable Future

The proliferation of renewable energy resources within Dominion also played an important part of Tuesday’s conference call. The company filed its 15-year long-term integrated resou r ce plan for Virginia on Friday. The IRP includes plans to increase solar, wind and energy storage capacity, with some increases coming from mandates in recent clean energy legislation signed into law in April by Gov. Ralph Northam. (See Va. 1st Southern State with 100% Clean Energy T a rget.)

Dominion’s long-term IRP also includes:

more than 5,000 MW of offshore wind planned by 2035, including the 2,600-MW Coastal Virginia Offshore Wind project that has a targeted in-service date of late 2026;
an increase of its solar fleet, already the fourth largest among U.S. utility holding companies, to develop and procure approximately 16,000 MW in the state over the next 15 years; and
expanding energy storage capacity to about 2,700 MW through battery storage pilot programs already approved and scheduled to be online in Virginia in 2021.

Farrell said the proliferation of renewable and intermittent resources across Dominion’s system will require continued investment in transmission infrastructure, especially as solar and wind emerge around the state.

Farrell said the Virginia State Corporation Commission’s pointed March 26 deci s i on denying certain elements of smart meter technology proposed by Dominion because of projected costs was a blow to the company.

The commission estimated that Dominion’s proposal, if approved in full, would have cost customers nearly $7 billion over 10 years. Smart meter technology was one of the most expensive elements of the plan, coming in at $752 million in total costs.

Renewables “will require an increasingly modern grid, which is why the recent [Virginia] commission decision to reject certain, although certainly not all, aspects of our most recent grid transformation filing was disappointing for our company and particularly for our customers,” Farrell said.

May 6, 2020

MISO Plugs SATOA Plan at FERC Conference

MISO defended its first storage-as-transmission proposal before FERC staff this week, maintaining the plan is a good interim measure while the RTO designs a more permanent approach.

The contentious proposal was the focus of a May 4 technical conference to allow FERC to weigh the merits of the plan. (See MISO SATOA Proposal Set for Technical Co n ference.) Many MISO stakeholders have complained that the proposed ruleset would give incumbent TOs an effective monopoly on storage assets functioning as transmission, harming competition. (See MISO SATOA Proposal Faces O pposition.)

The plan limits storage-as-transmission assets to transmission-only functions operated by MISO-defined transmission owners. As such, a new category of storage-as-transmission-only assets (SATOA) would be barred from simultaneous participation in MISO’s energy markets — for now. The RTO has contended that its plan will avoid introducing complexities around cost recovery, particularly the thorny issue of how to compensate non-TOs for providing transmission services.

But FERC in March ruled that MISO’s bid to include storage options in its annual transmission planning might be “unjust, unreasonable, unduly discriminatory or preferential,” suspending the provisions until Aug. 11 and calling for the conference (E R 20-588).

FERC Chairman Neil Chatterjee opened the commission’s first-ever virtual conference saying that he would pay special attention to the subject matter.

“I believe electric storage is a transformative technology that will be crucial to the grid of the future,” Chatterjee told listeners.

MISO SATOA — MISO’s Brian Pedersen | © *RTO Insider*

MISO Senior Manager of Competitive Transmission Administration Brian Pedersen called the proposal a “fundamental first step” in unlocking the full potential of energy storage facilities and said the plan represents a year-and-a-half of the RTO’s efforts in considering stakeholders’ opinions.

Pedersen acknowledged that some stakeholders advocated for storage to be allowed to simultaneously function as both transmission and energy market assets but said designing rules for dual-mode participation, a project selection process and a cost recovery mechanism for non-TOs would be too complex to implement right away.

“To do so would delay the issue by months, even years,” Pedersen said.

MISO officials said their approach to approving SATOA projects will factor in the length of time to get a SATOA resource operational versus traditional wires solutions, its effectiveness in resolving contingencies, availability and reaction times, what right-of-way space is necessary and the resource’s performance degradation over time. State-of-charge responsibilities will rest with the storage owner, though MISO could direct that a device be fully charged at certain times.

Pedersen said the RTO will also consider how the connection of a SATOA will impact generation awaiting interconnection in the queue.

Director of Planning Jeff Webb said MISO would not select SATOA devices in congested locations where several generation projects are vying for interconnection to avoid disrupting the generation queue. Stakeholders have voiced concern that SATOA projects would supersede planned generation projects by taking points of interconnection.

FERC staff said it wasn’t evident where the RTO’s proposal detailed such a no-harm process.

“I think it deserves some business practice manuals, but that’s the idea,” Webb said.

FERC staff also asked whether MISO expects SATOA to have the same impact on the generation interconnection queue as new traditional transmission projects.

“That’s hard to put your finger on … There’s a number of possibilities,” Webb said, adding that SATOA will be able to charge to offload lines as well.

Storage solutions that function more like energy resources will not be selected through the annual MISO Transmission Expansion Plan (MTEP) and will instead have to connect to the grid through the interconnection queue, Webb said. MISO expects that the more complicated a transmission issue is, the less likely a storage facility will be able to solve it.

Webb said the RTO envisions storage would most often resolve “N-1, steady-state issues.” A battery is less likely to “be at the right state of charge” and ready for dispatch to solve rapidly emerging second contingencies. But MISO executives also said SATOAs will solve transmission issues complex enough that MISO will need functional control of the storage facility.

“We’re at the front end of this; we haven’t seen all transmission problems that storage could solve,” Webb added.

Pedersen said that, “all things being equal,” MISO would lean toward traditional wires solutions in the event of a tie because wires are historically better at mitigating stacked contingencies and currently have longer lifespans.

The RTO’s MTEP report will include the rationale for SATOAs that are selected, Pedersen said. Stakeholders can address additional questions about SATOA selection to MISO’s subregional planning meetings throughout the year. SATOA will be subject to the same planning studies required of other transmission projects.

In response to a FERC staff question about whether SATOA energy injections would impact MISO’s market-based activity, Webb said even conventional wires have some impact on the energy market.

“Anytime you change the topology of the grid … yes, there will be some impact,” he said. “We think these situations are going to be minimal.”

“It isn’t a completely new concept for transmission to affect markets,” Webb added.

MISO will develop operational guides with SATOA owners to ensure energy market impacts are minimized. He said SATOAs, non-transmission alternatives (NTAs) and traditional transmission projects all involve assurances to the RTO that projects will be completed, either through the MISO transmission owners agreement or through individual interconnection agreements.

Not Comparable

DTE Energy’s Nick Griffin, whose company is a vocal opponent of MISO’s proposal, asked why the RTO couldn’t simply ask market-based storage facilities to keep some charge reserved for transmission issues.

Webb said that discussion is best reserved for MISO’s planned discussions on dual-mode participation in 2021.

Griffin said DTE Energy continues to believe that the RTO’s proposal creates unduly discriminatory preference for transmission owners over generation owners with comparable projects.

FERC staff at the conference said they were aware of the allegations of discriminatory treatment surrounding MISO’s proposal. They asked why the RTO’s proposal was necessary since it already has rules in place for selecting NTAs in the place of transmission projects. NTAs must first clear MISO’s roughly three-year generation interconnection queue before being placed in-service, while SATOAs need only be selected in the annual MTEP process for grid connection.

“If someone came and invoked undue preference, I’m not sure how we could address it besides give them the same deal,” FERC staffer Rahim Amerkhail said.

“What we’re trying to do here is not reclassify assets and redefine revenue streams but see how we can extract extra value from storage with these specific boundaries around what is generation and transmission,” Webb said.

Clean Grid Alliance’s Rhonda Peters said she took issue with the fact that SATOAs and NTAs will be subject to different study processes that can include diverging assumptions.

Webb responded that issues stemming from the different assumptions in generator interconnection studies and MTEP studies are not unique to SATOA projects. MISO is currently working with stakeholders to better synch the two. (See MISO Begins B id to Merge Tx, Queue Planning.)

“I think it’s really up for debate that the studies produce comparable results,” Peters said.

Responding to another FERC staff question, Webb said MISO has not contemplated a process for transitioning a SATOA to an energy market asset when it is no longer needed as a transmission resource due to load or grid changes.

“That’s something we have not bitten off in this filing,” he said.

May 6, 2020March 11, 2025

PSEG Turns Bullish on NJ FRR Option

Public Service Enterprise Group CEO Ralph Izzo said Monday it would be “logical” for New Jersey to abandon the PJM capacity market by adopting the fixed resource requirement (FRR) option.

The New Jersey Board of Public Utilities opened a proceeding to consider the FRR option in response to FERC’s December order expanding the PJM minimum offer price rule (MOPR) to all new state-subsidized resources — including PSEG nuclear units receiving zero-emission credits (ZECs) and offshore wind.

Speaking during a first quarter earnings call, Izzo said although capacity prices could be higher under an FRR, the state could see savings because the FRR would require only a 15% or 16% reserve margin. That’s far below the margins produced by PJM’s Reliability Pricing Model, which have been 24% or more for all but one of the delivery years between 2012/13 and 2020/21, according to one recent study. (See Report Slams PJM Forecasting, CO N E Estimates.)

“So, the unit cost is more [under FRR], but the number of units is fewer,” Izzo said. “The product of the two turns out to be less expensive in the state.”

Turnabout?

Izzo’s comments appear to represent a shift in his thinking. During his fourth-quarter 2019 earnings call in February, Izzo was skeptical that the state would switch to FRR, saying it would be “overkill” to pull 15,000 MW from the capacity market for 7,000 MW of offshore wind. (See PSEG’s Izzo Skeptical of F RR Option.)

A PSEG spokesperson said later Tuesday that Izzo’s “`seeming change of opinion’ is not a change at all.

“The first comment related to nature of FERC’s chosen solution – that the proposed solution, to allow an FRR-type arrangement for a single unit, was not selected by FERC, and as such, an entire FRR area would be needed, which would be `overkill’ in trying to solve the stated problem. The state’s desire to not pay twice for capacity in pursuing a clean energy agenda is perfectly logical, and because of FERC’s decision, it will simply need to do so on a broader scale.”

In his remarks Monday, Izzo cited the likelihood that the 7,500 MW of offshore wind planned by New Jersey by 2035 will be unable to clear the capacity auction under MOPR. The state awarded a contract for 1,100 MW to Ørsted in June 2019; commercial operation is projected for 2024.

“If you were to … take a look at what typical Eastern MAAC capacity prices have been and then you factor in what the capacity value of the offshore wind that might be granted by PJM, you quickly get to eight, if not nine figures in just a few years in terms of extra payments on the part of New Jersey customers for not having offshore wind be able to clear the auction,” Izzo said. “So, you have this double benefit that the state could realize if it designs the FRR in a competitive way that recognizes the carbon-free resources that it is committed to securing.”

Izzo said PJM’s MOPR compliance filing proposed an avoidable cost rate (ACR) price floor for PSEG’s nuclear units “that would preserve the full bidding flexibility to clear in the upcoming PJM capacity auction.”

“If New Jersey were to implement the FRR auction in broad terms, it would provide a choice for our nuclear units and the majority of our fossil fleet to bid into either PJM’s capacity auction or into a New Jersey FRR. An FRR could be structured to have a longer tenure, a preference for zero carbon generation and would have locational delivery requirements.”

Very Likely?

“It sounds like … it’s very likely that [New Jersey] probably will go for the FRR option. Is that the way we should be thinking?” asked Glenrock Associates analyst Paul Patterson.

“Look, they’re the final decider of that,” Izzo responded. “But I think that that is the logical thing for the state to do. Why New Jersey would want to pay twice for capacity in what is obviously an extremely ambitious carbon-free energy agenda would boggle my mind. New solar and offshore wind are not going to clear the auction at these ACRs. So, I think that the state would be greatly incented to do an FRR.”

PSEG is in discussions with Ørsted on a potential acquisition of a 25% equity interest in Ørsted’s 1,100-MW Ocean Wind project and expects to make a decision this fall. Izzo said the company’s decision will not be dependent on whether New Jersey opts for an FRR.

“The state is absolutely committed to building that project,” he said. ” … So, it’s really not a question of the FRR at all. The BPU order’s quite clear on what the commercial terms of that project will be, are and will be.”

The BPU is accepting comments on the FRR option through May 20. Izzo said he expected the BPU to make a decision on the FRR no sooner than the end of the year or the first quarter of 2021. “Remember the state really doesn’t have to worry about paying double for capacity now that the nuclear units are covered for at least for the foreseeable future until offshore wind comes online, and that’s not going to happen until 2024.”

Consumer Perspective

Stefanie Brand, director of the New Jersey Division of Rate Counsel, said whether FRR would be cheaper for consumers will depend on whether the program can adequately counter the market power of generators that could supply the state. She also said costs could be impacted by whether the FRR covers the entire state or just the Public Service Electric & Gas (PSE&G) zone.

“There aren’t going to be too many companies that are going to be in a position to set up an FRR. So, there’s going to be a market power element that’s going to have costs in it,” she said in an interview Tuesday. Izzo “doesn’t include that in his equation. And it’s money that might be going to his company, so that may have been the reason why it was included” in his comments.

Brand said her office hasn’t come to a conclusion on the wisdom of an FRR and hopes to learn more from an analysis PJM’s Independent Market Monitor is doing on a potential New Jersey FRR. The Monitor issued an an a lysis on the impact of Exelon’s Commonwealth Edison leaving the capacity market for an FRR in December and one on Maryl a nd’s options April 17 that concluded ratepayers are likely to see cost increases under an (FRR). (See PJM Monitor Defends FRR Analyses in MOPR Debate.)

PSE&G has suspended non-essential fieldwork while continuing emergency work during the coronavirus pandemic. | PSE&G

“We deregulated generation with the idea that competition was going to bring positive impacts in terms of [lower] prices. And it actually did for a long time,” Brand said. “We’ve kind of all been thrown into a frenzy right now. But I wouldn’t want to return to a situation where we had just a single unregulated monopoly. I don’t think that’s going to be a good outcome.”

Brand said her two biggest concerns over MOPR are how it affects offshore wind and the state’s basic generation service (BGS) auct i ons held by PSE&G and the state’s three other distribution utilities to provide service to customers not served by a competitive retailer.

In its April 16 order largely rejecting rehearing of its December MOPR ruling, FERC said the BGS is a “state subsidy because it is a state-sponsored process and includes indirect payments to the resource.” (See FERC: RGGI, Voluntar y RECs Exempt from MOPR.)

“I don’t have a whole lot of basis to really check his math … It may end up being cheaper” to leave PJM, Brand said. “We really need a full analysis of what we think the costs are going to be before we jump to any kind of conclusion. It could be that if [nuclear generation, solar and energy efficiency] clear then we just figure out a way to deal with the offshore wind problem [separately] and stay exactly where we are right now.”

COVID Impact

Izzo also talked about the impact of the coronavirus pandemic, saying the company’s PSE&G and PSEG Long Island units — which serve some of the areas with the highest incidence of confirmed COVID-19 cases — have suspended non-essential fieldwork while continuing emergency work.

Izzo said infection rates among PSEG’s 13,000 employees are below those for New Jersey and Long Island as a whole. About 1% of the workforce is currently self-monitoring.

The company is continuing its work on critical energy infrastructure projects although PSEG’s nuclear team reduced the scale of the current Salem Unit 2 refueling outage to protect all workers at the site, which also includes Salem Unit 1 and Hope Creek.

PSEG’s nuclear team reduced the scale of the current Salem Unit 2 refueling outage to protect all workers at the site, which also includes Salem Unit 1 and Hope Creek.| PSEG

Izzo said that the pandemic could result in “lumpy” access to mutual aid resources, noting that during a recent storm the company was able to secure only about 40% of the assistance it sought from other utilities.

“It was a combination of, candidly, utilities not willing to risk their own employees in terms of their exposure … and travel limitations put on some of the contractors,” he said. “So, if we have that experience when the trees all have leaves on them and the wind blows, then we will have to communicate extensively with customers about some of the likely delays that they will experience in being restored.”

Earnings

PSEG repor t ed non-GAAP operating earnings of $520 million ($1.03/share) in the first quarter, a drop from $547 million ($1.08/share) in 2019. Net income under GAAP was $448 million ($0.88/share) compared to $700 million ($1.38/share) in Q1 2019.

The company said its results were aided by rate-based expansion from transmission and distribution investments at PSE&G and ZEC revenue for PSEG Power, which added $0.07/share.

Those gains were offset by a scheduled decline in capacity prices, which reduced operating earnings by $0.11/ share, and the second mildest first quarter ever recorded in New Jersey.

Photo shows damage from a storm in South Jersey in April. PSEG said it received only 40% of the mutual aid assistance it sought from other utilities because of the pandemic. | PSE&G

PSE&G said pandemic stay-at-home orders caused a weather-normalized decline of 5% to 7% in electric load from the end of March through April. It said the ranges and the mix of usage among residential, commercial and industrial customers are imprecise because New Jersey lacks advanced metering infrastructure. (Izzo said the company hopes to complete BPU proceedings allowing it to spend $600 million on advanced metering infrastructure and $400 million on electric vehicle energy storage programs by early next year.)

Chief Financial Officer Daniel J. Cregg said that although PSE&G temporarily suspended all non-safety-related service shut-offs for non-payment during the COVID-19 crisis, the company can recover bad debt expenses through the state’s “societal benefits charge.”

Beginning June 1, the average PJM capacity price will rise to $168/MW-day from $116/MW-day, Cregg said. A scheduled decline in ISO-NE capacity prices will be partially offset by its nearly year-old Bridgeport Harbor 5 plant, which has a seven-year capacity lock at $232/MW-day.

PSEG Power has hedged more than 95% of its production at an average of $36/MWh for the remainder of 2020. It has hedged more than 55% of forecasted production at an average of $35/MWh for 2021 and more than 25% of output at $35/MWh for 2022.

May 6, 2020

Vistra Earnings Up as it Readies for New Normal

In announcing first-quarter earnings that beat expectations, Vistra Energy CEO Curt Morgan said Tuesday that the company took steps early in the year to prepare its operations for the harm wrought by the COVID-19 coronavirus.

Morgan is still getting used to the new normal.

“I never thought I would be hosting an earnings call from my home with my management team dispersed across the [Dallas-Fort Worth] Metroplex,” he said during Vistra’s first-quarter earnings call with financial analysts. “Yet, that is where we find ourselves today in these challenging times.”

Vistra reported adjusted earnings before interest, taxes, depreciation and amortization (EBITDA) of $850 million, as compared to $824 million for the first quarter of 2019. The company reaffirmed its 2020 adjusted EBITDA guidance range of $3.29-3.59 billion.

The Irving, Texas-based company uses adjusted EBITDA as its performance measure, saying this helps investors analyze the business.

In February, Vistra began suspending non-essential business travel and restricted access to corporate offices and plants. Morgan said the company was one of the first to test employees’ temperatures and use entry questionnaires at its facilities. He credited its proactive measures with completing or being on schedule with 86 maintenance outages at its Luminant plants “to ensure plant reliability for the critical summer months ahead.”

“Had we been levered like the [independent power plants] of the past, like back in 2016 when we emerged from bankruptcy, we may be having a very different discussion today,” Morgan said, a reference to its Energy Future Holdings predecessor, which eliminated $33 billion of debt before transitioning to its current form. (See Luminant, TXU Energy Emerge from Bankruptcy.)

Luminant’s Odessa-Ector gas-fired power plant | *Luminant*

Morgan said about 70% of its adjusted EBITDA comes from the ERCOT market, which — as in the aftermath of the 2008-09 recession — “is proving to be relatively resilient.” ERCOT twe e ted on Tuesday that its recent weekend peaks “appear” to have returned to pre-COVID levels and its weekday peaks are now down only 2%.

“We believe Vistra Energy is well-positioned to deliver strong financial results in 2020, even in the face of lower demand driven by COVID-19,” Morgan said.

Vistra’s share price opened Tuesday at $20.68 following the earnings release but finished the day down at $18.72. Shares had closed Monday at $19.01.