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September 5, 2024

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PSEG Looks to Post-fossil Future

Fresh from closing the sale of its fossil generating plants, Public Service Enterprise Group (NYSE:PEG) executives told investors during the utility’s fourth-quarter earnings call Thursday that they are looking at further investment in offshore wind projects and seeking a longer-term subsidy flow for their South Jersey nuclear plants.

The company on Wednesday completed the sale of its fossil plants in New York and Connecticut to a fund controlled by ArcLight Capital Partners, according to a company release, the last of its 6,750-MW portfolio of 13 fossil generating units, according to the company’s earnings presentation.

PSEG CEO Ralph Izzo said the sale will free up the utility to pursue a “robust set of regulated and contracted opportunities” that will enhance its “already compelling environmental, social and governance profile.” The company is looking at clean energy and infrastructure investments “to drive regulated utility growth, with the vision toward powering a future where people use less energy, and it’s cleaner, safer and delivered more reliably than ever,” he said.

The sale of the fossil units capped a year of “significant accomplishments,” Izzo said. Among the highlights: the sale of the company’s 467-MW portfolio of 25 solar plants in 14 states; the acquisition of a 25% share of the Ocean Wind offshore wind project under development on the New Jersey coast by Denmark-based Ørsted; and the announcement of a new goal to reach net-zero emissions by 2030, 20 years earlier than its previous target. The company also submitted nine proposals into the joint solicitation by the New Jersey Board of Public Utilities and PJM for transmission project proposals that will facilitate offshore wind projects.

Longer-term Subsidies

Izzo said he is looking to avoid the demands of applying every three years for subsidies to support the three nuclear generating plants — Hope Creek nuclear power plant and Salem 1 and Salem 2 — operated by PSEG in South Jersey, under the zero-emission certificate (ZEC) program. The approval in April of subsidies worth $300 million, the second three-year subsidy awarded to PSEG under the program, triggered sharp criticism from the New Jersey Division of Rate Counsel, the state’s consumer advocate, and environmental activists, who questioned whether the utility needed the funds to keep the generators operating. (See NJ Nukes Awarded $300 Million in ZECs.)

Izzo said he would like to see a “longer term” incentive program developed at the state level, and he is hoping for talks to resume at a federal level about awarding tax credits that would help support the operators of nuclear plants, such as PSEG.

“In the last four years, we had the creation of the legislation for the ZECs, and we had two rounds of ZECs,” he said, likening such a schedule to “sort of being masochists.”

“My sense from policy leaders — elected officials, regulators, key staff members — is we need these plants to run, at least until 2050,” he said. “The reality is, people have already expressed an interest in our nuclear plants. And they are outstanding assets. The issue is, how do you firm up the longer-term economic treatment beyond a three-year time frame?”

The U.S. Department of Energy last week invited public comment on the $6 billion Civil Nuclear Credit Program — funded under the Infrastructure Investment and Jobs Act — that will allow owners and operators of commercial nuclear reactors at risk of closure to competitively bid on credits to keep them in operation. (See DOE Launches $6B Nuke Credit Program.)

Izzo said the company also is in discussions that could lead to an increase in its offshore wind portfolio.

“We have a series of conversations underway that are related to Ocean Wind II, Skipjack [and] potential further upside of Ocean Wind I,” he said. The 1,148-MW Ocean Wind II project was one of two projects awarded leases in New Jersey’s second offshore wind solicitation in June. Ørsted, the project developer, also is developing two projects under the Skipjack name off the Maryland and Delaware coast. (See NJ Awards Two Offshore Wind Projects.)

Izzo said the company’s “initial early caution” about investing in offshore wind projects has diminished, in part because of increased understanding of the “commitment of other states in the development of supply chain [and] some of the regulatory hurdles that have been eased by virtue of some state actions and some federal actions.”

PSEG subsidiary PSEG Renewables is one of 25 companies eligible to bid in the auction underway this week for six leases in the New York Bight in a solicitation held by the U.S. Bureau of Ocean Energy Management.

Earnings

PSEG reported a net loss of $648 million (‑$1.29/share) for 2021, compared to net income of $1.905 billion ($3.76/share) for 2020. Non-GAAP operating earnings for 2021 were $1.853 billion ($3.65/share), compared to $1.741 million ($3.43/share) for 2020.

The loss in 2021 was from a pre-tax impairment charge of about $2.7 billion that stemmed from the sale of the fossil plants, the company said.

The company reported net income for the fourth-quarter of $445 million ($0.88/share), compared to net income of $431 million ($0.85/share) in 2020’s fourth quarter. Non-GAAP earnings for the quarter were $352 million ($0.69/share), compared to fourth-quarter non-GAAP earnings of $392 million ($0.65/share).

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‘Beautiful Symphony’ or Bust on Order 2222, Advocates Say

Distributed generation advocates and developers are frustrated with ISO-NE’s plan for complying with FERC Order 2222, but they say there are big prospects for improvement in a process that’s only halfway done.

The grid operator’s compliance filing, submitted to FERC earlier this month (on the fitting date of 2/2/22), would create new market participation models aimed at meeting federal regulators’ mandate to allow aggregated distributed energy resources to take part in its wholesale markets. (See NEPOOL PC Approves Tariff Changes for Aggregated DERs).

Industry representatives, speaking at the RE+ Northeast conference this week, said it simply fails to meet that goal.

“For front-of-the-meter DERs, I think ISO’s proposal has some benefits. For behind-the-meter DERs, it’s problematic. We don’t really think it accomplishes a whole lot, unfortunately,” said Nancy Chafetz, senior director of regulatory and government affairs at CPower Energy Management.

The proposal doesn’t allow resources behind a customer’s meter to participate directly in the market unless they have sign off from distribution utilities, which are unlikely to give the OK in the near term, Chafetz said.

Activating behind-the-meter DERs in the market could be valuable because there are whole fleets of them, including batteries, electric vehicles, hot water heaters and other devices in customers’ homes ready and waiting to be deployed to help stabilize the grid.

“If you’re a grid operator, emergencies don’t only happen between 4 p.m. and 8 p.m. every day on a weekday,” said Michael Macrae, senior director of regulatory affairs for ENEL North America. “Sometimes they happen at 10 in the morning on a Tuesday. And there’s no way to call all the [DERs] and say, ‘The person who uses you would be totally clueless if you just stopped for an hour.’”

The ISO-NE filing fails to capture that flexibility, he said.

“We would love to have all these resources be available for ISO dispatch and earn capacity market revenues for providing that service,” Macrae said.

Still Time on the Clock

The good news, say advocates, is that ISO-NE’s filing to FERC — and its counterparts from other regions — were just part of the conversation and not the end of it.

“Even though we were disappointed in all of the compliance filings that came in, I think we need to acknowledge that this is an ongoing conversation that will need to be iterative even after FERC rules,” said Chris Rauscher, senior director of market development and policy at Sunrun.

For example, there are rules outside of 2222’s scope that would prevent some resources from bidding into the market, like PJM’s must-offer rule, which requires resources participating in the capacity market to also bid into the energy market.

Advanced Energy Economy has been one of the most vocal critics of ISO-NE’s 2222 filing and is expected to protest it at FERC.

The trade group’s managing director Jeff Dennis said this week that commission staff have been asking detailed questions about previous filings from California and New York.

“That said to me that the commission is digging in and looking very carefully at these compliance filings,” he said.

Potential for a ‘Beautiful Symphony’

Despite their worries about the regulatory process, industry advocates see a bright future for DERs on the horizon.

“Bringing all of these DERs in aggregation to respond to wholesale markets, in my mind, is the biggest opportunity I’ve ever seen in my career for unlocking flexibility on the demand side,” Dennis said.

He gave the example of school bus electrification, which could produce “incredible” resources for flexibility.

“In five years, if FERC and the markets get it right, it will be a beautiful symphony every day,” Rauscher said.

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Japan Working to Make Hydrogen a Transportable Energy Commodity

The Biden administration’s $9.5 billion bet on hydrogen becoming an industrial and transportation fuel in the future may come down to how easily the colorless and odorless gas can be transported.

Mitsubishi has been working on that problem for years and believes it now has a solution: store the gas in a “carrier,” a common industrial organic compound such as methylcyclohexane (MCH). A liquid at ambient temperatures, MCH can be handled like gasoline and moved around the world in tankers and pipelines.

Working in a consortium with other Japanese companies, Mitsubishi proved the concept in 2020 with a project in which green hydrogen was repeatedly produced in Brunei, a small sun-drenched country on the island of Borneo and shipped to Japan in ordinary tankers.

Kiichiro Fujimoto, general manager of Mitsubishi’s Infrastructure Solutions Department, explained the process and Japan’s goals to cut carbon emissions in half by 2030 during a webinar produced Thursday by the D.C.-based Center for Strategic and International Studies.

Fujimoto explained that the hydrogen was mixed with toluene, a common solvent and degreaser, creating the liquid MCH.

“MCH is very chemically stable, [exhibits] a very minor loss during the long-term storage and long-distance transportation. It’s easy to handle,” he said. When the hydrogen was recovered from the MCH in Japan, the solvent was shipped by tanker back to Brunei.

Mitsubishi and its partner companies in the Brunei project believe that the MCH method can be used to ship hydrogen from Australia and Chile, two countries that are planning to make hydrogen with renewable power. (See Global Hydrogen Conference Reveals Plans to Ship Sunshine.) Middle Eastern companies are also planning to produce green hydrogen, which could be shipped to Europe as well as Japan.

Scale — both in production and in use — is the key to making hydrogen affordable, Fujimoto said.

“Here is the important part: In order to support this billion-[dollar]-size project, we need a very reliable hydrogen producer, a very reliable hydrogen buyer, and we need a very reliable hydrogen carrier technology and a company that operates all these operations,” he said, adding that his company is working on business opportunities in Singapore and Europe.

Snam, an Italian energy infrastructure company, is working to create a hydrogen supply chain not only in Italy but across Europe to move the hydrogen once it arrives from overseas.

Giovanna Pozzi, in charge of renewables and power supply for hydrogen at Snam, said the company has been blending hydrogen with natural gas in ongoing tests of its pipelines.

In a controlled test, she said the company delivered gas containing 10% hydrogen to a glass maker and a bakery. Neither business had any problems, nor did the pipelines, she said.

“We have been able to define the new technical standards for the injection of hydrogen into our pipes. We’re moving to different countries into Europe because we are teaming up with the 23” other companies, she said. “We are exchanging information with a very ambitious aim: the creation of the first European hydrogen backbone.”

The hydrogen-dedicated network would be about 40,000 km, she said, of which 70% would be repurposed existing gas lines and 30% new construction. (See Roundtable Looks at Storage, Hydrogen to Decarbonize Northeast.)

But to make this work, the 23 companies need new common, European-wide policies and regulations, which currently do not exist, she said.

“I think that the key success factors that we are talking about are technical constraints and standards, new standards for these gases. And then the regulation and funding support,” she said.

Neil Navin, vice president for clean energy innovations at Southern California Gas (NYSE:SRE), said his company has also worked on blending and sees aggregating demand for hydrogen as important to moving to large-scale production and use.

Pointing out that California has a significant industrial base that could use hydrogen in place of hydrocarbons.

“The key to electrolytic [green] hydrogen is to put the solar panels in the place where the sun is most intense, and most often … making sure that you can situate your renewables in those locations, co-produce hydrogen and then transport that hydrogen into the demand centers,” he said. “That really dictates the topology of transportation.” (See related story, SoCalGas Proposes Hydrogen Pipelines.)

Navin added that the hub concept advocated by the Biden administration — producing a lot of hydrogen in an area abundant in renewables or natural gas — just makes sense financially.

“We found that there is a real logic to looking for the areas of highest renewable penetration for the source of hydrogen,” he said, rather than producing it locally.

“It seems counterintuitive, but once you look at the math, the economics become more apparent. So, what I think you’ll find in each region, especially in the United States, is that demand will likely not move, [and] the factory will stay where it is.

“The power plant will stay where it is. People will not move to the renewables; you will have to move the hydrogen to them.”

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Entergy Regulators Ask FERC to Settle Grand Gulf Dispute

Three regulatory bodies are demanding answers on FERC’s apparent delay in addressing a complaint over the management of a southwestern Mississippi nuclear plant.

Attorneys for the Louisiana Public Service Commission, Arkansas Public Service Commission and Council of the City of New Orleans filed a motion Monday to again request FERC schedule a hearing on a complaint alleging maladministration at the 1,428-MW Grand Gulf nuclear station (EL21-56).

The regulators asked for a remedy for Entergy subsidiary System Energy Resource, Inc.’s (SERI) “significant customer harm arising from years of imprudent operations and mismanagement.” They pointed out that their original complaint was filed almost a year ago, on March 2, 2021.

“Nearly every other complaint filed in the commission’s docket year 2021 has been acted upon by the commission in some manner, yet this complaint is still pending initial commission review,” lawyers for the regulators wrote.

The regulators reminded FERC that it has a duty under the Federal Power Act to act swiftly on complaints and said the D.C. Circuit Court of Appeals “has expressed dismay at the lengthy time lags experienced by litigants before the commission.”

“What constitutes a ‘reasonable’ time to conclude a controversy may vary with the circumstances of each case; however, it is not reasonable for the commission to take over a year to evaluate whether or not a complaint merits further investigation,” the regulators said, adding that they aren’t aware of any reason for FERC’s delay.

The bodies said they have supplied the commission with supporting evidence and sworn affidavits that could be used in a FERC investigation.

Grand Gulf station is the nation’s largest nuclear reactor. Entergy sells the output at wholesale to its Arkansas, Louisiana, Mississippi and New Orleans subsidiaries.

Last year’s complaint described “imprudent operation” and “subpar performance” at Grand Gulf and sought refunds and rate reform on more than $1 billion in costs passed on to Entergy customers.

The regulators tapped Critical Technologies Consulting (CTC) to investigate the plant’s operations from 2012 to 2020. They said CTC uncovered costly safety issues and substandard output performance. They also said Entergy inappropriately used an outdated economic analysis in 2012 when it decided to undertake approximately $800 million worth of construction to bulk up the plant’s capacity.

The Louisiana PSC said the uprate work paradoxically led to diminished electricity production from Grand Gulf. Entergy customers often found themselves paying for the plant’s full fixed investment and operating costs in addition to replacement energy sourced from other plants, the New Orleans City Council said. The regulators said Grand Gulf’s frequent outages drove shortages and upped energy prices in the MISO markets.

The Nuclear Energy Institute’s data indicates Grand Gulf is the worst-performing nuclear plant in the nation, with a 66.3% capacity factor from 2018 to 2020. The plant’s last-place finish is well below the 77.9% capacity factor of Michigan’s Fermi 2, the other least-reliable unit.

The regulators estimate that their ratepayers are owed about $361 million for the added expense of Grand Gulf outages from 2016 to 2020. They also want the 2012 upgrades investigated and possibly refunded.

“We promised New Orleanians that we would hold Entergy accountable over their responsibility to provide reliable, affordable power to their ratepayers,” New Orleans Council President Helena Moreno said last year. “Grand Gulf is the single largest energy resource for the city of New Orleans, and we need it to be operating safely, at full capacity, and at a reasonable cost. We are asking FERC to help us get that plant running efficiently again as well as seeking refunds to make it right by our people.”

“Entergy customers deserve a full look at the potential imprudent management of Grand Gulf and, eventually, appropriate refunds if it is found that Entergy passed unnecessary costs onto those customers,” then-Louisiana PSC Chairman Craig Greene said.

Entergy said it doesn’t see anything amiss with the yearlong wait.

“While we don’t typically comment on pending litigation, this is a large, complex case, and we do not believe there has been any undue delay in setting the case for hearing.  Further, we dispute the allegations that we have not prudently operated and managed Grand Gulf. In fact, this past year, Grand Gulf achieved all-time plant records for both gross generation and net generation in megawatt-hours,” Entergy spokesperson Mike Bowling said in an emailed statement to RTO Insider.

Bowling said in 2021, Grand Gulf’s net generation was nearly 12 million MWh, while its gross generation surpassed the 12 million MWh mark.

Entergy had not responded to requests for comments at press time on the year-long delay or how it plans to react should FERC set a hearing in the matter.

Grand Gulf’s unit power sales agreement with Entergy’s member companies is at the heart of another ongoing FERC complaint (EL20-72). In that docket, Louisiana, New Orleans, Arkansas and Mississippi regulators have accused Entergy and SERI of massaging accumulated deferred income tax numbers to overcharge customers for Grand Gulf’s sale-leaseback arrangement and recovering in rates through the sales agreement the costs of lobbying, image advertising and private airplane use.

In recent testimony, Entergy Vice President of Regulatory Services Joshua Thomas characterized the proceeding as a “kitchen sink” complaint, covering “a wide range of complex subject areas over a 30-year time period.” Thomas said the retail regulators “claims are vague, and the requested relief is undefined.”

Entergy maintains it doesn’t include below-the-line costs in ratemaking and that no over-collection occurred.

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FERC Approves PJM Capacity Auction Date Changes

FERC on Tuesday approved PJM’s revised schedule for the upcoming Base Residual Auctions (BRAs), incremental auctions and associated pre-auction deadlines through the 2026/27 delivery year (EL19-58).

PJM’s updated schedule proposed conducting the 2022/23 third incremental auction (IA) beginning on Monday, as scheduled, and continuing to use the forward-looking energy and ancillary services (E&AS) offset, as it was used in the 2022/23 BRA.

The 2022/23 BRA, originally scheduled for January, will now take place on June 8; the 2024/25 BRA moves from August to December; the 2025/26 auction moves from February 2023 to June 2023; and the 2026/27 auction moves from August 2023 to November 2023. The 2027/28 BRA will be back on schedule in May 2024.

The first and second IAs are canceled for the 2023/24, 2024/25 and 2025/26 BRAs, and the first IA is canceled for the 2026/27 BRA.

In a remand order issued Dec. 22, FERC reversed its approval of PJM’s forward-looking E&AS offset. The commission said PJM must now revert to the previous, backward-looking offset. (See FERC Reverses Itself on PJM Reserve Market Changes.) The commission said it recognized PJM would need to delay the BRA to implement a revised E&AS offset, a key variable in calculating the net cost of new entry for resources in capacity auctions.

In the remand order, the commission directed PJM to submit a compliance filing proposing a new schedule for the 2023/24 delivery year and subsequent BRAs. PJM updated the schedule in the middle of January and made an official filing on Jan. 21. (See PJM Reveals Preliminary Capacity Auction Timeline.)

On Tuesday, FERC said it found that PJM complied with its directive by filing an appropriate revised schedule and that it included “sufficient justification” for the schedule.

“PJM reasonably minimizes the delay of the 2023/24 BRA by proposing to revise only pre-auction deadlines impacted by the E&AS offset revision and the general delay of the auction, which necessitated the use of an updated load forecast,” FERC said in its order. “PJM also reasonably proposes to allow capacity market sellers to update only the E&AS offset portion of their unit-specific requests. We agree with PJM that this approach will allow for administrative efficiencies by not requiring duplicative information to be resubmitted, potentially allowing PJM to avoid unnecessary delay.”

The commission agreed with PJM’s proposal to eliminate some of the IAs. It also said it found it “reasonable” for the RTO’s proposal to retain limited discretion of up to 10 business days to set the specific deadlines associated with any pre-auction activities.

“We agree with PJM that it would be cumbersome and administratively inefficient to seek further amendments to the auction timelines for minor adjustments to the deadlines,” FERC said in its opinion. “However, we recognize PJM’s commitment to post the specific dates of pre-auction activities no later than eight months prior to the commencement of any associated BRA in order to ensure that all market participants are aware of the relevant deadlines.”

Danly Concurrence

In a separate concurrence, Commissioner James Danly said he agreed with the updated schedule, stating that PJM’s capacity auctions “have been delayed for far too long.” Auctions that have historically been looking three years ahead “have had their periodicity reduced to a year or less,” he said

Danly said the commission in its role as regulator “bears most of the blame for the sorry state of PJM’s auction schedule,” but he also faulted the RTO for the auction delays. He said PJM’s filing made to “eviscerate its minimum offer price rule” in the summer and another auction delay it requested in September contributed to the limited timing of the auctions.

“This last delay is particularly galling,” Danly wrote. “Given its role in causing and requesting auction delays, PJM’s call for the commission to ‘expeditiously’ and ‘promptly issue an order and provide much needed market certainty’ is … brazen.”

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FERC Doubles down to Deny Killingly Rehearing

FERC on Wednesday issued an order affirming its decision to deny rehearing to NTE Energy on the termination of the company’s capacity supply obligation for its Killingly Energy Center (ER22-355-001).

The decision brings ISO-NE one step closer to being able to move forward with releasing the results of Forward Capacity Auction 16, which have been held in limbo since the auction was held Feb. 7.

In its order, FERC again agreed with ISO-NE that NTE was not on track to meet a May 2024 critical path milestone for commercial operation of Killingly, using previously confidential documents submitted by the RTO to cement its case against the developer of the Connecticut natural gas-fired project.

The order includes the first public discussion of a report from Lummus Consultants International, which concluded that Killingly could achieve construction by 2024 on an “aggressive” schedule, but only by obtaining full notices to proceed without financing in place.

“The record does not support accepting this premise,” FERC wrote, and the Lummus report also concluded that a “realistic scenario” would see Killingly miss the deadline by several months.

Also made public for the first time were details of a letter from Korea Western Power Co. that asserts it was seeking government approval for a financing deal for Killingly, but, as FERC notes, the company “makes no commitment to finance the … project … nor does it indicate the level of financing being considered.”

Despite the resolution of the rehearing request, ISO-NE is still unable to announce the results of FCA 16 because a stay from the D.C. Circuit Court of Appeals remains in effect, an RTO spokesperson said. The grid operator has asked the court to dissolve that stay, given that NTE has also forfeited its financial assurance and therefore was on track to lose its CSO regardless of FERC’s ruling.

The results of FCA 16 as well as the planning timeline for next year’s FCA 17 have been thrown into doubt by the court’s last-minute ruling, which upended the process. (See Killingly Uncertainty Could Delay Capacity Auction Results Another Month.)

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CenterPoint Energy Turns in Solid 2021 Performance

CenterPoint Energy (NYSE: CNP) continued its recovery from a disastrous 2020, reporting strong year-end and fourth-quarter earnings on Tuesday.

The Houston-based utility last year earned $1.39 billion ($2.28/diluted share), compared with a loss of $949 million (-$1.79/diluted share) a year earlier.

Fourth-quarter earnings were $641 million ($1.01/diluted share), up sharply from $151 million ($0.27/diluted share) for the same period of 2020.

Earnings adjusted for non-recurring gains came in at $0.36/share, exceeding Zacks Investment Research’s consensus estimate of $0.31/share.

<img src="//www.rtoinsider.com/wp-content/uploads/2023/06/140620231686782180.jpeg" data-first-key="caption" data-second-key="credit" data-caption="

CenterPoint CEO David Lesar 

” data-credit=”CenterPoint Energy” data-id=”3730″ style=”display: block; float: none; vertical-align: top; margin: 5px auto; text-align: left; width: 200px;” alt=”Dave-Lesar-(CenterPoint-Energy)-FI.jpg” data-uuid=”YTAtNjg3Nzg=” align=”left”>CenterPoint CEO David Lesar  | CenterPoint Energy

“2021 was a great year for CenterPoint with quarter after quarter of meeting or exceeding expectations,” CEO Dave Lesar said in a statement. “We have had seven quarters of execution … and are continuing to find ways to increase our capital plan over the course of our 10-year plan to benefit our customers and our investors.”

Central to the utility’s plans is the recently announced regional master energy plan with the city of Houston, labeled Resilient Now. CenterPoint is exploring the use of mobile electric stations that can power 200 to 300 homes while line crews restore damaged facilities and other grid and infrastructure hardening and modernization measures.

Lesar told financial analysts CenterPoint is now enrolling some of Houston’s surrounding communities. “Our focus is, ‘What does the grid need to look like in Houston and surrounding areas, given the fantastic growth we’ve seen in this market?’” he said.

In January, CenterPoint sold gas distribution businesses in Arkansas and Oklahoma for more than $1.6 billion. Future transactions could add to the utility’s ability to complete Resilient Now.

“It’s just a great option to have as we look at our ability to spend more capital here in what is essentially one of the crown jewels of CenterPoint, which is Houston Electric,” Lesar said, referring to the Houston distribution company.

CenterPoint’s share price closed at $26.49 Wednesday, 11 cents off Monday’s pre-earnings close.

Entergy Earnings Down from Year Prior

Entergy (NYSE: ETR) on Wednesday reported fourth-quarter earnings of $259 million ($1.28/share) and year-end earnings of $1.12 billion ($6.02/share) That was down from 2020’s fourth quarter of $388 million ($1.93/share) and the full year of $1.39 billion ($6.90/share).

The company’s results-adjusted non-recurring gains came in at $0.76/share, beating Zack’s consensus estimate of $0.70/share.

“Despite the unique challenges presented in 2021, we continued to deliver on our commitments and exceeded the midpoint of our guidance range,” Entergy CEO Leo Denault said.

The New Orleans-based company set its 2022 EPS guidance at $6.15-$6.45/share.

Entergy’s share price ended the day at $104.74, giving away most of its gains. That was only a 23-cent gain from the day’s previous close.

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RI Agency Approves PPL Acquisition of Narragansett Electric

A Rhode Island agency overseeing the acquisition of Narragansett Electric by PPL (NYSE:PPL) provided its official approval on Wednesday, overcoming the last major regulatory hurdle in the $3.8 billion deal with National Grid (NYSE:NGG).

The Rhode Island Division of Public Utilities and Carriers provided its final 334-page report and order on the acquisition after several months of public testimony and filings, determining that the deal would not adversely impact customers in the state.

“The division finds that after a thorough examination of the record in this docket, including the many public comments that were offered, the evidence demonstrates: that the facilities for furnishing service to the public will not thereby be diminished [if the petition is approved], and that the purchase … [and] sale … and the terms thereof are consistent with the public interest,” it said.

The announcement comes just days after PPL’s fourth-quarter earnings call in which the deal was a primary discussion topic among the company’s leadership and stakeholders. (See PPL Announces Losses, Dividend Cut in Q4 Call.)

PPL spokesman Ryan Hill said the company was “pleased” that the division approved the sale of Narragansett. It will announce the completion of the acquisition upon close, which CEO Vince Sorgi said last week could occur as soon as March.

“We appreciate the division’s thoughtful consideration of our petition for approval,” Hill said. “We look forward to the successful close of this transaction and are excited about the opportunity the acquisition will present for PPL to drive significant value for Rhode Island families and businesses and advance a cleaner energy future.”

PPL received FERC approval for the purchase of Narragansett in September, but the utility needed final approval from the division for the deal to go through. (See FERC Approves PPL Acquisition of Narragansett.)

In filings and testimony last year regarding the acquisition, staff from the office of Rhode Island Attorney General Peter Neronha opposing the deal, saying PPL provided insufficient information to ensure ratepayer protection and that more protections needed to be required as part of the approval.

The AG staff also said compliance with Rhode Island’s 2021 Act on Climate should be a condition of approval. The state climate law, signed in April by Gov. Dan McKee, requires a net-zero economy in the state by 2050, but National Grid and Narragansett have claimed the emissions-reduction statute does not apply to public utilities. (See Rhode Island Makes 2050 Net-zero Target Legally Binding.)

During last week’s earnings call, Sorgi said the company was confident it would ultimately win approval for the acquisition. He said PPL has been a “clear leader” in the development and deployment of the kind of smart grid technology Rhode Island will need in achieving its decarbonization goals in the Act on Climate.

The deal was first announced almost a year ago. (See PPL to Sell UK Business, Acquire Narragansett Electric.) It gives Pennsylvania-based PPL its first foothold in ISO-NE after operating in PJM since its inception.

National Grid spokesman Ted Kresse said the sale is a transfer of “ownership of 100% of the outstanding shares of common stock” of Narragansett. Narragansett will continue to own and operate its assets and “maintain all of its franchise rights for the provision of electric and gas distribution service in Rhode Island, under the management and control of PPL Rhode Island.”

“We look forward to completion of the sale,” Kresse said.

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Dragos: Electric Industry Cyber Preparations ‘Very Successful’

The cybersecurity landscape in 2021 was marked by an escalation of both known cyber vulnerabilities in U.S. industrial organizations and activity groups seeking to take advantage of those weaknesses, according to an analysis released by cybersecurity firm Dragos on Wednesday.

At the same time, the company said North American electric utilities were “very successful” over the year at taking action to safeguard their industrial control systems (ICS) and operational technology (OT) computer networks from the emerging global threats.

Robert Lee (Dragos) Content.jpgDragos CEO Robert Lee | Dragos

Dragos CEO Robert Lee attributed the sector’s success partially to a history of taking the danger of cyberattacks seriously, but said a more direct cause of its resilience in 2021 was utilities’ positive response to the Biden administration’s “100-day sprints” for a range of critical infrastructure systems.

Biden’s initiative was launched in July for most sectors, but it started in April for the electric industry. (See Biden Reinstates Trump Supply Chain Order.) That effort, led by the Department of Energy’s Office of Cybersecurity, Energy Security and Emergency Response, encouraged utilities to invest in technologies to allow near-real-time situational awareness and response capabilities in ICS and OT networks, deploy procedures and equipment to enhance detection capabilities, and improve the cybersecurity posture of critical infrastructure information technology networks.

“What was very beneficial with the presidential 100-day sprints is they said … ‘We’ve heavily invested in preventative measures, firewalls, segmentation, antivirus passwords, all that kind of stuff, [but] we don’t have a lot of ability to detect and respond to threats,” Lee said in a media call introducing the firm’s 2021 Year in Review. “So we don’t care how you get it done; we just care that you get something in place to start getting insights inside … these OT or ICS networks, to where you can start finding issues, risks, threats, and sharing those insights to the government.”

The report did not directly identify how many cyberattacks in 2021 were directed at particular industries, outside of ransomware. In this area, the firm registered 13 incidents involving the energy sector. By comparison, twice as many incidents affected the transportation sector and nearly three times as many impacted food and beverage companies. Manufacturing was hit hardest, with 211 incidents in 2021; of those, less than three involved goods manufactured for the energy sector.

Threat Landscape Remains Active

This is not to say that electric utilities can rest easy. Two of the three new activity groups Dragos identified last year directly target the energy sector. One, which the firm has dubbed Kostovite — in keeping with its practice of not associating threat actors with nation-states — focuses on North America and Australia, while another, Petrovite, focuses on Central Asia.

Kostovite is seen as the more mature of the two, having reached stage 2 of the ICS kill chain, a model of ICS attacks adapted from Lockheed Martin’s cyber kill chain framework. A 2015 white paper from SANS Institute describes stage 1 of such an attack as “espionage or an intelligence operation.” In stage 2, an attacker must “specifically develop and test a capability that can meaningfully attack the ICS.”

Characteristics of the Kostovite group (Dragos) Content.jpgCharacteristics of the Kostovite group, identified by Dragos last year, which focuses on the renewable energy industry in North America and Australia | Dragos

Dragos first identified Kostovite when responding to an attack on “a major renewable energy operation and maintenance firm” with facilities in North America and Australia. The attackers first gained access to legitimate account credentials, which they then used to gain access to multiple generation facilities. Once inside, Kostovite made its way around the network without using any outside tools or code, which Lee observed denotes a high level of skill. The group was able to hide inside the network undetected “for at least a month.”

The firm also pointed out that some concerning security practices are still often found among electric utilities, with limited visibility into OT and ICS networks rated as “frequent” occurrences; poor maintenance of security perimeters and allowance of external connectivity to secure systems were both considered “common,” and only shared credentials among staff ranked as “uncommon.”

By contrast, in the nuclear industry only limited visibility was rated as “frequent,” while the other three categories were considered “rare,” the lowest rating. On the other hand, the rail and food and beverage industries both saw all four categories listed under “frequent.”

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California Sets 6 Million Heat Pump Goal

The California Energy Commission adopted a new goal of installing six million electric heat pumps in the latest version of its Integrated Energy Policy Report (IEPR), which addresses the challenges facing the state’s electricity, natural gas and transportation fuel sectors.

An aggressive effort to electrify buildings is needed for the state to meet its legislatively mandated targets of getting 60% of its energy from renewable resources and reducing greenhouse gases 40% below 1990 levels — both by 2030, the CEC said in one volume of its 2021 IEPR that commissioners approved Feb. 16.

“The year 2030 is just around the corner,” the report said. Replacing most fossil-fueled equipment in that time is impossible, but gas-fired furnaces and water heaters wear out regularly and need replacement. Doing so with electric heat pump appliances could significantly reduce natural gas consumption in a relatively short time, the report said.

“That makes the market transformation of new equipment sales a key priority,” it said.

“Heat pumps are a critical enabling technology for achieving building decarbonization,” it said. “As such, the CEC is recommending a goal of installing at least 6 million heat pumps by 2030. Further, the CEC commits to working with stakeholders — including manufacturers, labor, and environmental advocates — to accelerate the market to meet this goal and to push beyond it toward comprehensive migration to heat pumps for space and water heating.

“Each replacement of major equipment presents a precious opportunity to achieve long-term savings and make additional performance improvements to [a] building. Also, opportunities for energy savings and GHG reductions will be missed if equipment is not installed to meet California Energy Code requirements.”

Commissioners unanimously supported the new goal along with other portions of the IEPR.

“The piece I wanted to call out in this IEPR is the six million heat pump goal,” Chairman David Hochschild said. “I am a big believer in goals. I’m encouraged that we’re doing this.”

He likened the heat pump target to the goal set by Gov. Jerry Brown in 2018 of putting 1.5 million zero-emission vehicles on the road by 2025.

“At the time, there were a lot of people who said that was outlandish [and] it was never going to happen,” Hochschild said. “We’ve now blown by a million electric vehicles, and we’re well on our way to surpassing that goal.”

Setting an official objective for heat pumps will drive investment and innovation, he said.

“I have every confidence that we’re not only going to reach this goal, but that we’re going to surpass it.”

The CEC’s energy efficiency update to the state’s building code in August will help, he said.

It required developers of new single-family homes to install either an electric heat pump water or space heater.

The market share for heat pumps in California is less than 6% in new home construction, but the building code requirement is expected to increase demand and make heat pumps more affordable and widely available.

“This will juice the market for heat pumps,” Commissioner Andrew McAllister said at the time.

The recent launch of the $120 million TECH Clean California program, intended to jumpstart the market for residential heat pumps, could also help the effort. It provides incentives of $3,000 or more to homeowners who replace gas furnaces or water heaters with electric heat pumps. Combined with local incentives, for instance in the San Francisco Bay Area and Sacramento, those amounts can more than double to $6,600.

“TECH represents a milestone in California’s efforts to decarbonize the building sector and combat climate change,” the Natural Resources Defense Council said in a blog post last week.