The Northeast Power Coordinating Council does not anticipate any major reliability issues this summer, in part because of depressed demand resulting from the COVID-19 pandemic.
“Hot, muggy weather, resulting in the heavy use of air conditioning, remains the single largest factor affecting peak electricity demand during the summer months,” NPCC CEO said Edward Schwerdt in a media call this week announcing the organization’s summer Reliability Assessment.
Sagging Demand Linked to COVID-19
NPCC is the regional entity for New England, New York, Ontario, Québec, New Brunswick and Nova Scotia. | NERC
Demand in the regional entity’s territory is expected to peak at 104,156 MW, slightly higher than last year’s forecasted peak of 103,548 MW. (See NPCC Sees Lower Summer Peak for 2019.) The growth is primarily because of the return of a large industrial customer in Québec. Despite a net decrease of 700 MW in NPCC’s overall installed capacity from last year, the RE is projecting a spare operable capacity (capacity over and above reserve requirements) during the summer of between 12,700 MW and nearly 21,000 MW.
As with other parts of North America, utilities in the Northeast have seen significant changes in customer behavior across their service areas since many states and cities began ordering residents to stay at home because of the pandemic. Over April 6-10, average electric consumption in New York City during the 8 a.m. hour was 18% lower than expected, while forecasters for ISO-NE have seen declines of 3 to 5% and usage patterns resembling those of snow days. Ontario also reports overall demand “beginning to trend low” and load forecasting models in Québec have consistently overestimated morning and afternoon peaks since March 23.
Philip Fedora, NPCC’s assistant vice president of reliability services, described the drop in demand as an unplanned but useful cushion that can help protect against “adverse reliability impacts related to COVID-19 from unavailability or inoperability of key facilities” resulting from factors such as workforce disruptions, interruptions to fuel supply and deferred maintenance.
“I would like to emphasize that all NPCC areas have plans to address potential [pandemic-related] transmission system operational impacts during this summer,” he added. Preparations are also underway for such severe system conditions as reductions in the ability to import power from neighboring regions, transmission constraints and reductions in demand response programs.
Healthy Regional Forecasts
The report included a snapshot of regional changes in generation across NPCC’s footprint since last summer and projected peaks this year.
NYISO predicts peak demand of 32,296 MW, 86 MW lower than last year’s forecast. Despite a drop in generating capacity of 978 MW because of the retirement of several generating facilities, the state forecasts installed capacity of 38,745 MW during the peak week, with spare operable capacity of 1,711 MW.
ISO-NE is expecting peak demand of 25,158 MW against installed capacity of 31,115 MW, with spare operable capacity of 3,197 MW. Limited amounts of maintenance and construction are planned for natural gas pipelines in the region, but these are not expected to result in significant deliverability issues.
Ontario has added 1,499 MW of generating resources composed of natural gas, wind and solar facilities since last summer, for a net gain of 1,461 MW. The summer peak demand forecast for the province’s Independent Electricity System Operator is 22,194 MW, 89 MW higher than last year. Spare operable capacity during peak weak is projected at 1,558 MW.
Québec, New Brunswick and Nova Scotia, which are winter-peaking, project weekly spare operable capacity margins for the summer of at least 5,300 MW and 1,100 MW, respectively. Peak load for Québec is predicted at 21,635 MW, up 630 MW from last year, while peak load for the Maritimes is anticipated at 3,370 MW, from 3,255 MW last year.
Planning for New Pandemic Challenges
While Schwerdt and Fedora see the region as well positioned for the summer, they acknowledged that the COVID-19 outbreak has the potential to introduce new complications. For instance, NERC recently warned of increased cybersecurity risks from an expanded remote workforce, along with the likelihood of distributed energy resources serving a larger portion of overall load than anticipated by grid planners, leading to challenges with predicting demand. (See “Cybersecurity, DER Risks Highlighted,” PPE, Testing Top Coronavirus Concerns for NERC.)
Fedora emphasized that the RE and its associated entities are aware of these issues and have considered them in their planning. But while these concerns are legitimate, they can be addressed without losing sight of fundamental yearly challenges.
“They are used to operating a transmission system under low-load conditions, it’s just perhaps that these conditions are going to occur more frequently than before,” Fedora said. “We can’t predict the future, but we can look at cause and effect, and we looked at several of these scenarios. … We don’t think there is a real liability from a resource adequacy and transmission adequacy point of view for this summer.”
The California Public Utilities Commission unanimously approved a settlement Thursday with Pacific Gas and Electric that imposes record penalties of more than $1.9 billion on the bankrupt utility for safety and maintenance lapses that led to massive wildfires in 2017 and 2018.
But the unusual structure of the agreement left some dissatisfied — including the commissioner who authored it.
Instead of levying fines, the commission agreed to a package that denies PG&E recovery from ratepayers of approximately $1.82 billion in wildfire-related expenses, meaning shareholders will pay the costs. But half that amount probably would have been denied by the CPUC during ratemaking proceedings anyway because of PG&E’s failure to operate its grid safely, said Commissioner Clifford Rechtschaffen, who led the effort to penalize PG&E.
The company also agreed to $114 million in system enhancements and corrective actions, to be paid by shareholders, and to return to ratepayers the hundreds of millions of dollars in tax savings it expects to recoup from operational expenses not covered by rate increases. The company will still benefit from tax savings from capital expenditures in keeping with Internal Revenue Service rules, Rechtschaffen said.
The only fine that’s part of the agreement — $200 million that would otherwise go to the state’s general fund — will be “permanently suspended,” according to the terms of the settlement.
“I recognize that a permanent suspension of the fine is deeply unsatisfying to many,” Rechtschaffen said. “Several intervenors strongly opposed this provision. I share this frustration. I think it’s important to keep in mind, however, that this penalty action is only one of many aggressive steps that the commission’s taking to hold PG&E accountable for its actions and to prevent future misconduct.”
The commission has demanded enhanced oversight of PG&E and greater enforcement authority as part of its proposed approval of the utility’s bankruptcy reorganization plan, which it intends to hear on May 21. (See PG&E Deal with Gov. Allows for Utility’s Sale.)
Even so, Rechtschaffen said, “A fine is clearly appropriate here given the unprecedented scale and scope of harm from the wildfires that PG&E caused and because fines convey unique societal opprobrium.”
The massive wildfires fires of 2017 and 2018 ignited by PG&E equipment included the Camp Fire, which leveled much of the town of Paradise and killed 85 residents, and the Northern California wine country fires of October 2017. A CPUC investigation found numerous lapses in equipment maintenance, line inspections and vegetation management that were the basis for the penalties.
The fires were a “grim chapter in PG&E’s history that had devastating consequences,” Rechtschaffen said. “Our investigation found that PG&E’s misconduct caused 15 of the wildfires resulting in unprecedented damage — over 100 people killed, 25,000 structures destroyed, hundreds of thousands of acres burned and the destruction of an entire community in Paradise.”
The fires also led to bankruptcy, “an extraordinarily disruptive process for a company that provides essential utility services,” he said.
PG&E said in a statement Thursday that it accepted the CPUC’s decision and “will work to implement the shareholder-funded system enhancements and corrective actions called for in the settlement.”
“We remain deeply sorry about the role our equipment had in tragic wildfires in recent years,” the utility said.
PG&E’s Past Penalties
Thursday’s settlement topped the CPUC’s previous record of $1.6 billion in penalties imposed on PG&E in April 2015 for the San Bruno gas pipeline explosion in 2010, which killed eight and destroyed part of a suburban San Francisco neighborhood. PG&E was convicted in federal court of six felonies related to that disaster and remains on probation. (See Judge Orders PG&E to Improve Line Inspections.)
The settlement replaced an agreement reached in December between PG&E and the CPUC’s Safety and Enforcement Division, among others, that would have penalized PG&E a total of $1.625 billion in disallowed costs and system enhancements, including $900 million in wildfire costs that the company may not have been entitled to recover from ratepayers in the first place, the commission said.
An administrative law judge recommended changes to that settlement in February, including $198 million in additional disallowed costs and the $200 million fine.
PG&E appealed, denying its potential liability for fires even as it was negotiating a guilty plea deal to 84 counts of involuntary manslaughter connected to the Camp Fire, Rechtschaffen said.
“The stridency of PG&E’s appeal was highly unfortunate and deeply disappointing,” he said, given the utility’s “strongly professed recognition of the need to dramatically transform its culture, its approach to safety and its professed commitment to working collaboratively in the future with its regulators.”
PG&E told the commission it would have to pay the $200 million fine out of the $13.5 billion trust for wildfire victims it plans to fund in its bankruptcy case. Otherwise the fine might upset the billions of dollars in financing agreements it needs to emerge from bankruptcy, PG&E contended.
The commission ultimately decided to adopt the judge’s recommendations but to suspend the $200 million fine and allow PG&E to keep its tax write-offs for capital expenditures but not operational expenses. (The tax savings for all PG&E’s disallowed wildfire costs is estimated to be about $500 million.)
PG&E’s financial circumstances, and its need to emerge from bankruptcy by June 30 to participate in a state wildfire liability fund, made the concessions necessary, Rechtschaffen said.
The San Bruno fines included a $300 million state fine, a $400 million refund to gas customers and $850 million for gas system safety improvements.
PG&E was flush with cash then. Today, it is set to emerge from bankruptcy heavily indebted with its share price about $11 at the close of trading Thursday versus $52 when the CPUC levied the San Bruno fines.
“It is an extremely rare set of circumstances that justify a departure from our normal penalty rules as we’ve done here,” Rechtschaffen said of the agreement.
CenterPoint Energy on Thursday said it wrote off $1.6 billion in asset losses from its Enable Midstream Partners oil and gas pipeline and storage investment, resulting in a $1.2 billion loss (-$2.44/share) for the first quarter.
A year ago, CenterPoint reported first-quarter earnings of $140 million ($0.28/share). Last quarter’s revenue of $2.2 billion was similar to the same period a year earlier.
The Houston-based company took the impairment in Enable following the partnership’s recent cutbacks in the face of economic headwinds. Pummeled by the global slump in petroleum demand and the COVID-19 pandemic, Enable halved its quarterly distributions to investors and cut its capital expenditures for 2020 by $115 million, among other cost reductions.
CenterPoint has a 53.7% limited partner ownership interest in Enable and is expected to take a $115 million hit from the move on an annualized basis.
“We thought that was the right level [for distribution cuts],” interim CEO John Somerhalder said during a conference call with investors. “We’re confident in Enable’s ability to weather the downturn.”
Still, CenterPoint is taking other actions to “fortify its financial position,” announcing:
A $1.4 billion equity investment that will eliminate all anticipated equity needs through 2022 and fund a “robust” $13 billion investment program.
The appointment of former Halliburton CEO David Lesar and Barry Smitherman, who has chaired the Texas Public Utility Commission and the Railroad Commission of Texas, to the company’s board.
The creation of a new Business Review and Evaluation Committee, chaired by Lesar and reporting to the board. The committee will conduct a comprehensive, five-month review of CenterPoint and its businesses.
Somerhalder said the equity investment, combined with the recent $850 million sale of a pipeline business and the pending $400 million sale of its Energy Services natural gas retail business, will be used to deleverage CenterPoint’s balance sheet and the overall credit profile.
“These equity investments provided a transformational opportunity for the company to operate from a position of heightened strength and flexibility,” Somerhalder said.
CenterPoint is also working with regulators across its diverse footprint to address the recovery of COVID-19 expenses. Nearly 70% of its regulated jurisdiction has recovery mechanisms in place, the company said.
The utility’s share price outperformed the market Thursday by closing at $17.81, an 11.45% gain from Wednesday’s close. CenterPoint stock hasn’t seen that level since early April.
OGE Energy Takes $492M Loss
Enable’s distribution cuts also led to a quarterly loss for its other major investor, OGE Energy, holder of a 25.5% limited partner interest and a 50% general partner interest.
OGE took a $780 million impairment in reporting a loss of $492 million (-2.46/share) for the quarter. A year ago, the company reported a $47 million ($0.24/share).
“While the Enable write-down was impactful to earnings this quarter, it was not a reflection of the cash flows generated by those assets,” CEO Sean Trauschke said. OGE still recorded a cash distribution of $37 million from the partnership, compared to $35 million in 2019.
The company revised its year-end earnings guidance from $2.19 to $2.31 per average diluted share to a net loss of -87 to -77 cents/share.
OGE’s share price gained 4 cents during the day, closing at $29.29. The company’s stock has lost almost 34% of its value since the year began, when it was $44.06/share.
Xcel Energy 3 Cents Shy of Earnings Expectations
Xcel Energy reported first-quarter earnings of $295 million ($0.56/share), falling short of 2019’s first-quarter performance of $315 million in profits ($0.61/share) and analysts’ expectations of 59 cents/share.
The Minneapolis-based company said the pandemic did not significantly affect the results, laying the blame instead on the negative impact of weather. Retail electricity sales were only down 1% in the quarter, the company said.
Preliminary sales revenue for April indicates a 9.6% drop, with commercial and industrial sales experiencing a 13.7% fall.
“We are responding to the economic impact from this global pandemic by implementing contingency plans to minimize the impact on our financial results,” CEO Ben Fowke said in a statement. “However, these are unprecedented times, and the ultimate economic impact from the pandemic may be greater than anticipated.”
Xcel plans to cut operating and maintenance expenses by as much as 5% and institute a hiring freeze.
Xcel reaffirmed its 2020 earnings-per-share guidance of $2.73 to $2.83/share, based on assumptions of a “severe” pandemic-related impacts in the second quarter with a slow economic recovery and a 4% loss in sales over last year. It still cautioned that such a scenario could undercut earnings by 17 cents/share.
“We expect to be a part of the solution to get the economy back on its feet … but this is a fluid situation,” Fowke told analysts during Xcel’s earnings conference call.
Xcel’s share price jumped to $62.06 after the market’s open Thursday, following a close the day before of $61.22. After the earnings call, the stock price slid to a close of $59.96.
NRG Energy’s first-quarter net income rose 29% to $121 million ($0.49/share) on the addition of a new revenue stream from a recent acquisition and margin enhancement initiatives partially offset by mild weather across core markets.
In a call with analysts Thursday, CEO Mauricio Gutierrez touted the company’s strong position despite the social disruptions stemming from the coronavirus pandemic.
“First, we initiated a comprehensive response to COVID-19 focusing on maintaining safe and reliable operations,” Gutierrez said. “Second, given the changes that we have made to our integrated business, we were able to deliver strong results during the first quarter and reaffirm our full-year financial guidance.”
Gutierrez also highlighted enhanced disclosures on the business, including the introduction of new integrated regional segments, with the company working to integrate its Eastern markets in the same manner it has in ERCOT, where it “moved from having two distinct businesses, Retail and Generation, to one integrated business with a regional focus.”
| NRG
The company’s West segment will only have generation revenue and cost set, as there is no ability to replicate the integrated model because of a lack of competitive retail markets, he said.
“Because the East and West segments are not fully integrated, the sensitivity to changes in power prices is not as optimized as it is in Texas,” Gutierrez said.
Texas Rides High
CFO Kirkland Andrews noted that NRG as a whole saw $349 million in earnings during the first quarter. The company’s Texas segment accounted for $195 million, up $19 million largely because of the increased load from the acquisition of Stream Energy last year.
But the company reported power demand declines across all regions, except for that of ERCOT residential, which saw a 7% rise last month.
Load reductions by RTO/ISO in April 2020 | NRG
“To put the mild weather into context, ERCOT and the Northeast saw temperatures that were 20% and 17% warmer than the 10-year normal for the first quarter,” he said.
In these “unprecedented times,” Gutierrez said to “expect most of the adverse impact from COVID-19 to come from customer payment-related items, like bad debt. At this point, we estimate that to be around $50 million. We will look at and be studying this impact through prudent cost management and ERCOT’s relief fund.”
While the small business, commercial and industrial sectors have been negatively impacted, the impact on specific utilities will depend on the customer mix in their portfolios, Gutierrez said.
“In our case, we are heavily weighted towards the Texas residential customer,” he said.
Looking ahead to summer, Gutierrez noted that “Texas already began a partial reopening of the economy. This suggests that the severe impact to small businesses we have seen in April may ease as the economy reopens. … The impact to summer load is difficult to assess at this point, but I can tell you that summer prices will be dependent on wind production and weather.”
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 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.
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.
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.”
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.
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 reported 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.
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 presented 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: April 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 (ER18-1639). 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: March 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 project 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 Plans 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 (ER20-89). (See FERC Rejects ISO-NE Fuel Security 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.”
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 Conference.) 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 Opposition.)
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 (ER20-588).
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 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 Bid 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.
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, CONE 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 FRR 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 analysis on the impact of Exelon’s Commonwealth Edison leaving the capacity market for an FRR in December and one on Maryland’s options April 17 that concluded ratepayers are likely to see cost increases under an (FRR). (See PJM Monitor Defends FRR Analyses in MOPRDebate.)
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) auctions 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, Voluntary 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 reported 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.
