MISO is ready to begin testing some of the capabilities of its new market platform as the effort to develop the system enters its fourth year, stakeholders learned last week.
“It’s really an exciting time for the program because we’re pivoting from foundational work to delivery,” MISO Senior IT Director Curtis Reister told stakeholders on a Market Subcommittee conference call Thursday.
Reister said members’ IT departments will soon begin testing MISO’s new market user interface software in a customer test environment.
MISO expects it will begin transitioning to the new interface by the third quarter of 2021, running the system in parallel to the old platform for several months to allow members to phase in the change before the old interface is officially retired in early 2022, Reister said.
The RTO reports that 291 companies currently use its market user interface.
“It’s not like every member has to transition on the same day. This allows members to attempt to transition … and go back and forth as many times as needed,” Reister said.
Because of vendor delays, MISO now says it’s unsure if it can meet a self-imposed June deadline to demonstrate the operation of its private cloud using non-Critical Infrastructure Protection data. The new private cloud will house the modular platform, replacing the current server-based platform.
The RTO plans to migrate data to its new private cloud for testing and import modeling information to its one-shop model manager this year. (See “Private Cloud Prepped for New Market Platform,” MISO Board of Directors Briefs: Dec. 12, 2019.)
By the end of the year, MISO will have uploaded its operations data in the model manager, which is scheduled to go live next year, Reister said.
“Modeling is interwoven in a lot of MISO processes,” Reister said of the importance of a singular repository for the RTO’s many planning models. MISO currently relies on several different means to collect and validate grid information for modeling.
MISO said the contract and delivery date of work on its new day-ahead market clearing engine is currently under negotiations. Its goal is to have the existing platform and a version of the new platform running in parallel for testing purposes in 2021, paving the way for the eventual retirement of the old platform. The RTO hopes to have the new clearing engine in production in the third quarter of 2022.
MISO executives have said that the monolithic nature of the current market platform is a major limiting factor in adapting its market to accommodate new products that seek to incentivize availability of the RTO’s shifting resource mix.
“2020 is the fourth year of the program, and it represents a turn in focus of the work,” Vice President of Market System Enhancements Todd Ramey said during MISO Board Week in March. “Whereas the first three years of the program were primarily focused on extending the life of the legacy platform … this year we’re really making the switch to completing major projects and bringing some of this online.”
ISO-NE is planning to bring staff back to its Holyoke, Mass., headquarters in phases over the summer, CEO Gordon van Welie told the New England Power Pool Participants Committee on Thursday.
The RTO has had 95% of its workforce working remotely because of the COVID-19 pandemic since March 14, with remote deployment to continue through at least June 1, and is paying special attention to the health of crews for the two control centers, van Welie said.
ISO-NE has some questions about President Trump’s May 1 executive order banning “any acquisition, importation, transfer or installation of any bulk power system electric equipment” controlled by or involving any foreign country or person, van Welie said. (See Trump Declares BPS Supply Chain Emergency.)
The order directs the energy secretary within 150 days to “publish rules or regulations implementing the authorities delegated.”
In response to stakeholder questions, van Welie said nothing in the order has the RTO concerned, but he noted the need to live with uncertainty during the Energy Department’s 150-day period for ruling on imported equipment that might fall under the ban of such critical energy infrastructure.
Pandemic Load Factors
ISO-NE created a “backcast” model to provide a baseline of what loads should have been absent the pandemic, COO Vamsi Chadalavada said.
“The backcast is for March 1 to April 28, so that’s about 59 days, and we’ve built a composite of what a load curve would look like by averaging every hour of those 59 days,” Chadalavada said.
[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to clarify their presentations.]
Comparison of average hourly actual loads to backcast loads (March 1 through March 28) | ISO-NE
“It’s interesting to see how those societal actions are reflected in a daily load profile … a slower morning ramp, a later morning peak; mid-day loads are lower, evening peaks are lower, and the transitions to night loads are less steep,” he said.
The RTO continued to observe approximately 3 to 5% lower loads in April, and there has been an approximately 6% reduction in average load when comparing this year to last, he said.
The pandemic accounts for up to 5% of the decreased load, but additional energy efficiency and PV installations likely make up a majority of the difference.
“Energy efficiency has been on a steady track in recent years, but PV has picked up lately, so it’s not clear exactly how consistent this contribution to lower load is with historical trends,” Chadalavada said.
Average hourly actual load deviations from backcast model | ISO-NE
Faster Boston RFP
The RTO’s competitive transmission solicitation for Boston garnered 36 proposals from eight qualified parties by the March 4 deadline. With the evaluation process moving faster than expected, stakeholders will see the early cut in July rather than August.
“I know there’s been a lot of interest in the responses that we’ve received for the Boston [request for proposals], and in the volume, and the range of dollars, and the timelines,” Chadalavada said.
The RTO is confident that some proposals in the phase one study process are going to be available for New England ahead of June 1, 2024, the current retirement date for Mystic 8 and 9, he said.
“I think we had left you with an expectation that we will be sharing with all of you those proposals that move from phase one to phase two at the end of August,” he said. “We are going to be able to do that in July, so it’s at least going to be an acceleration of up to four weeks, but that doesn’t mean we’re stopping there. If we continue to make the progress that we are, we could maybe even be sooner in front of you with those proposals.”
Summer Meeting to be Virtual
The Participants Committee’s Summer Meeting will be held virtually June 23 because of the coronavirus pandemic. There will be an online “Future Grid” educational session on June 24. More information will be released as plans are finalized, NEPOOL said.
Consent Agenda
The PC on its consent agenda approved a revision to Operating Procedure 14 (OP-14) related to technical requirements for generators, demand response resources, asset-related demands and alternative technology regulation resources.
The PC also approved clean-up changes and enhancements to the RTO’s billing policy, which were raised in conjunction with certain clean-up changes to the ISO-NE Financial Assurance Policy that are still under review by the NEPOOL Budget and Finance Subcommittee. The subcommittee discussed the changes during its March 26 and April 21 teleconferences, and no members objected to the changes.
Litigation Report
NEPOOL Secretary David T. Doot’s monthly litigation included several items of note, starting with the RTO’s filing of its Energy Security Improvements (ESI) market design with FERC on April 15, for which the commission has set a May 15 comment deadline date (ER20-1567).
The second item was a technical conference on combined or hybrid resources to be held at FERC on July 23, focusing on a generation resource paired with storage.
The third item concerned the New England Ratepayers Association (NERA) filing of a petition for declaratory order on April 14 asking FERC to outlaw net metering for rooftop solar generation.
NERA argues that the commission has exclusive federal jurisdiction over wholesale energy sales from generation sources located on the customer side of the retail meter. The commission on May 4 extended the deadline for comments in the dispute over net metering until June 15 (EL20-42). (See related story, FERC Extends Deadline in Net Metering Dispute.)
Another litigation item concerned a request that FERC convene a technical conference on the topic of carbon pricing, with the filing giving people until May 21 to submit comments.
The final item was ISO-NE’s Inventoried Energy Program (Chapter 2B) proposal, for which a federal court granted FERC’s motion to suspend briefing and for voluntary remand, directing parties to file status reports at 90-day intervals beginning July 20. (See “OKs Early EIP Sunset,” ISO-NE Sending 2 Energy Security Plans to FERC.)
MISO’s plan to crop some load-modifying resources’ capacity credits remains unpopular with many stakeholders, prompting the RTO to postpone the new accreditation for a year.
Scott Wright, Resource Adequacy Subcommittee liaison, announced during a conference Wednesday that the new accreditation approach will be pushed to the 2022/23 planning year beginning June 2022.
MISO Director of Resource Adequacy Coordination Zakaria Joundi said the RTO would still file with FERC for the changes this month, adjusting the effective date for 2022 instead of 2021.
“So next year, there will be no change; the current methodologies will stay the same. But starting [the year after], you’ll begin to see some changes,” Joundi told stakeholders.
MISO plans to set an LMR’s capacity accreditation at either an average of its actual availability over a three-year period or its tested availability, whichever is less. LMRs that can respond more often and with shorter lead times will receive a larger capacity credit; those that can respond in six hours or less to 10 or more calls per year will receive a full capacity credit.
Last month, MISO eased its proposal to eliminate the capacity credits of LMRs with lead times greater than six hours, offering them a 50% capacity credit for two years if they can respond to at least 10 calls in a year. The RTO maintains that LMRs needing more than six hours’ notice don’t help mitigate emergency conditions. (See MISO Offers Concession on LMR Capacity Credit Plan.)
MISO LMR capacity accreditation plan | MISO
Beginning in the 2023/24 planning year, MISO will no longer offer any capacity credits for LMRs with six hours or greater lead times or that cannot respond to at least five calls in a planning year, Joundi said.
In spite of last month’s revision, stakeholders overwhelmingly voted to postpone the new accreditation via an email ballot that closed April 15.
Energy counsel Jim Dauphinais, on behalf of the Louisiana Energy Users Group, said a 2021/22 planning year effective date “does not provide sufficient time for action to be taken to avoid a potentially large unnecessary exit of capacity from the MISO market.”
Gabel Associates’ Travis Stewart asked if MISO expects LMR owners to use the extra year to make modifications to be more available or simply expects them to collect another year’s worth of capacity credit.
“If MISO can’t depend on them, then the accreditation should show up immediately,” Stewart said.
Joundi said the additional year will allow load-serving entities to reopen LMR contract provisions to either amend availability times or revise the number of calls to which resources are willing to respond.
“It’s more about administration … and less about technology,” he said.
MISO said it “encourages stakeholders that can obtain reductions in notification times or increase call limits to do so prior to the 2022/23 planning year,” especially for LMRs in local resource zones that rely more heavily on load modification.
Some stakeholders agreed, saying the more immediate change would cause some demand response to abandon the MISO capacity market.
WEC Energy Group’s Chris Plante asked MISO to first perform loss-of-load-expectation analyses to measure the benefit of a reduced LMR capacity credit.
“We believe that LMRs with lead times greater than six hours, but less than 12 hours, provide some reliability value and should receive some amount of credit after 2023,” Plante said in comments to the RTO.
Other stakeholders again asked MISO to wait and see how new LMR rules work out before proposing a new LMR capacity accreditation. FERC early last year allowed MISO to require LMRs to offer capacity in accordance with a seasonal availability report provided to the RTO and commit to deploying based on a notification time no longer than 12 hours. (See MISO LMR Capacity Rules Get FERC Approval.)
“MISO should allow the impacts of the changes from 2019 to be studied before making these additional changes. Furthermore, any additional changes to LMRs should be done as part of the larger resource accreditation effort to be undertaken by MISO and not in this piecemeal, one-off, incremental approach,” Vectren’s Michelle Quinn said.
MISO this year will pursue a rethink of all other resource accreditation, saying its current approach results in “inequitable treatment among resource types providing different levels of reliability contribution.”
“We definitely want to show stakeholders what’s clearing in the Planning Resource Auction versus what is showing up in the MISO Communications System. I think that’ll give transparency into what’s available to our operators when conditions may be tight,” planning adviser Davey Lopez said. Once cleared in the capacity auction, MISO’s planning resources use the Communications System to convey their availability to the grid operator.
PPL remains optimistic it will meet its 2020 financial targets even with the full impacts of the COVID-19 pandemic still unknown, executives reassured investors in a first-quarter earnings call Friday.
Bill Spence, in his final earnings call as CEO before he steps down on June 1, said PPL’s response to the pandemic has kept it in a “strong position in the face of this challenge.” He cited the company’s liquidity and steps taken during the first quarter to strengthen its financial position by accessing capital markets.
PPL has not changed its 2020 forecast of $2.40 to $2.60/share, Spence said, despite much of the company’s service areas being on lockdown for the past six weeks. Spence said the lockdowns have resulted in lower commercial and industrial load and higher residential loads in all its territories.
“At this point, it is too early to predict clearly what the pandemic impact will be on full-year results,” Spence said. “This will depend on how long the pandemic lasts, the pace and extent of the economic recovery and the degree companies continue to employ work-from-home protocols, which is what’s driving the higher residential loads.”
Q1 Earnings
PPL’s first-quarter net income came in at $554 million ($0.72/share), a 19% jump over the $466 million ($0.64/share) during the same period last year. The company said its per-share earnings rose to 72 cents, compared with 64 cents in the first quarter of 2019.
Adjusted for nonrecurring gains, company officials said earnings were $514 million ($0.67/share), compared to $508 million ($0.70/share) last year. Operating revenue was $2.05 billion, down from almost $2.08 billion last year.
CFO Joe Bergstein said the adjusted earnings decrease was primarily because of a warmer-than-normal winter in the U.S. He said the warm winter drove a -3-cent variance compared to 2019 and about a 5-cent variance in the company’s forecast, as heating degree days were down by about 30% in Pennsylvania and 15% in Kentucky compared to normal weather conditions.
PPL Q1 Earnings | PPL
Based on observations in April, Bergstein said commercial and industrial load was down 15 to 25% depending on the region. He said those declines were partially offset by higher residential demand, with 1 to 3% increases in its U.K. operations and 5 to 8% increases domestically.
Bergstein also noted losses in the company’s U.K. business, with its regulated segment earning 39 cents/share, a 2-cent decrease compared to 2019. Bergstein said decreased U.K. earnings were attributable to lower pension income and higher operation and maintenance expenses.
Bergstein said PPL remains “very well situated” to survive the pandemic, with about $5 billion in total available liquidity. He said during March and April, the company was able to secure term loan facilities of $400 million for 12-and 24-month durations and also issued $1 billion of senior notes.
“We believe these positions have the company very well positioned from a liquidity perspective for the remainder of 2020,” Bergstein said. “While we have $700 million of additional debt maturities, at the operating companies in November, we believe we’ll have the ability to access the capital markets to refinance that debt.”
COVID-19 Response
The background of the pandemic flavored much of the earnings call.
PPL President Vince Sorgi, the person tapped to take over as CEO after Spence’s retirement, said the company has taken several measures to keep employees safe from the pandemic, including temperature testing, requiring masks and gloves, and enhancing its industrial cleaning. Sorgi said critical employees, which are primarily control room operators, have been split into multiple teams, and as much as 40% of its total workforce is working from home.
“While we are certainly managing the current crisis at hand and ensuring that our customers and employees are protected during these difficult times, I want to further emphasize that we remain focused on the long-term strategy of the company,” Sorgi said. “For PPL and many utilities, that includes the transition to cleaner energy, and we continue to position our utilities to fight climate change in a manner that balances the needs of our customers and the environment.”
Consolidated Edison’s profits fell nearly 12% in the first quarter, with the utility attributing the decline to the effects of the economic shutdown and unusually warm weather in New York.
The company on Thursday reported net income of $375 million ($1.13/share), compared to $424 million ($1.39/share) during the same period in 2019.
During a call with analysts, CEO John McAvoy pointed to the direct impact of the COVID-19 outbreak on the region the utility serves.
“During this pandemic, all of us at Con Edison remain solely focused on the health and safety of our employees and our customers while continuing to provide the highest level of reliable service,” CEO John McAvoy said.
“Like many Americans, we have lost family, friends and colleagues to this virus,” McAvoy said. “Throughout, I am immensely proud of our dedicated workforce who have risen to the challenge and to our unions’ leadership in working with us. We must and will summon all the compassion, grace and strength needed to provide for the recovery.”
The company’s earnings forecast assumes the restart of some paused commercial activities by early June, with a phased process that continues through the third quarter.
C&I Volume and Revenue Drop
Con Ed mobilized a pandemic planning team in January and an incident command system structure on March 16, the company said in its earnings presentation.
With approximately 8,000 of its 14,000 employees working from home or remotely, Con Ed illustrates the truth of recent analysis that predicts the economic fallout from the pandemic will weigh most heavily on utilities most dependent on commercial and industrial load. (See Researchers: Pandemic to Sting C&I-dependent Utilities.)
The company’s main revenue driver, Consolidated Edison Company of New York (CECONY), showed electric delivery volume for March 16 to April 30 down 19% in the commercial segment and 17% in the industrial segment. Revenues in both categories in the same period were each down 16%.
Estimated non-weather impact on CECONY electric delivery volume and revenues for March 16 to April 30 | Con Edison
CECONY residential electricity deliveries were up 11% in the period to April 30 and revenues up 7%.
Con Ed is supporting the community in various ways during the pandemic. It deployed a 1-MW generator to support the field hospital set up at the Brooklyn Cruise Terminal in Red Hook, and expanded grid service or provided engineering services for other emergency field hospitals throughout the city and Westchester County. The company also is making 40,000 face shields in its machine shop for health care workers.
MISO says it is contemplating creating a seasonal design for its resource adequacy construct to manage potential reliability risks outside of the summer months.
“Patterns of risk may already be shifting out of peak load periods,” Jessica Harrison, MISO director of research and development, told stakeholders during a Resource Adequacy Subcommittee teleconference Wednesday.
MISO has said its current annual resource adequacy construct and yearly loss-of-load expectation (LOLE) study may not be enough to address the reliability risks it encounters throughout the planning year.
An evolving fleet is nudging MISO’s loss-of-load risk to periods outside of the typical summer peak, the RTO said. It is increasingly encountering resources that have different capabilities depending on the season and a “notable increase in aging baseload units operating sub-annually.”
Harrison said MISO’s reliability risk also “increases noticeably in winter when accounting for seasonal patterns in outages.” She said the RTO’s analyses of 2018 data have found a “moderate” risk of loss of load in all of January and some days in February, in addition to the expected moderate to severe reliability risks in the summer months.
Harrison characterized the analyses as “initial” to determine whether “something other than an annual forced outage rate makes sense” in MISO’s LOLE study.
DTE Energy’s Polaris Wind park | DTE Energy
WPPI Energy’s Steve Leovy pressed MISO to provide a “comprehensive” loss-of-load analysis that proves a clear shift to risks outside of summer.
“The history of maximum generation events isn’t satisfactory. … MISO still hasn’t shown an analysis that shows a resource adequacy risk in non-summer seasons,” Leovy said. “I believe, in MISO’s mind, they’ve already decided there’s a risk. We shouldn’t be at a place yet where MISO proposes seasonal changes. And I’m very afraid that we’re already there, and we’re going to skip over a demonstration.”
Harrison said MISO’s initial studies don’t yet provide a full justification for seasonality.
“However, we are starting to see some indicators,” Harrison said, adding that stakeholders should expect more MISO analyses on seasonality in resource adequacy.
“We’re trying to understand needs before we move into design,” she said, adding that MISO also “has to keep the pace up” in reacting to industry change.
Customized Energy Solutions’ David Sapper urged MISO to conduct its future analyses by giving some consideration to low load levels brought on by an economic depression triggered by COVID-19.
MISO’s second annual Forward Report, released in March, concluded that it must soon break out its annual LOLE study and Planning Resource Auction by season. (See MISO Forward Report Stresses Near-term Change.) The RTO said it could begin making filings to move toward a seasonal resource adequacy construct late this year and in 2021.
Johannes Pfeifenberger, a principal of The Brattle Group, said multiple organized markets have turned to a seasonal resource adequacy construct, with NYISO’s two-season capacity market implemented the earliest in 1999. CAISO enforced monthly resource adequacy requirements for load-serving entities starting in 2004.
He said PJM in 2016 attempted to implement a year-round availability requirement while maintaining a summer reliability benchmark.
“That’s not really working well for some seasonal resources,” Pfeifenberger said of PJM’s treatment. “They’ve left it up to seasonal resources to figure out how they’re going to provide a year-round product.”
Pfeifenberger said even non-market entities like Southern Co. and the Tennessee Valley Authority have “migrated somewhat to winter reserve markets.” He said Alabama Power shifted to winter peaking in 2011 and now uses a 25% winter planning reserve margin compared to a 15% summer planning reserve margin.
The COVID-19 pandemic might not have impacted Eversource Energy’s first-quarter earnings, but it is affecting the company’s business both as a frontline utility and developer of offshore wind energy projects, analysts heard last week.
Most of the company’s customer service staff are working from home, and state regulators have delayed two rate case decisions until fall. And while federal officials are keeping up with offshore project reviews, a New York judge has delayed by 10 weeks a state-mandated hearing into the company’s 130-MW South Fork project off Long Island.
Eversource is waiting for DPU approval of its $1.1 billion purchase of Columbia Gas, with closing expected by the end of Q3 2020. | Eversource
During an analysts call Wednesday, Eversource reported first-quarter earnings of $334.8 million ($1.01/share), up more than 8% from the same period a year ago.
Eversource is New England’s largest utility company, with regulated subsidiaries offering retail electricity, natural gas, and water service to approximately 3.6 million customers in Connecticut, Massachusetts and New Hampshire.
The company is about to get bigger, confident that it will receive regulatory approval for its $1.1 billion acquisition of Columbia Gas’ 320,000 natural gas customers in Massachusetts.
“We are acquiring the assets of Columbia Gas of Massachusetts, not any of the liabilities associated with the tragic September 2018 incident in the Merrimack Valley,” CFO Philip Lembo said in an earnings call.
Current Rate Cases
New Hampshire Gov. Chris Sununu issued an executive order last month that will allow state regulators to delay ruling on a Eversource subsidiary Public Service Company of New Hampshire’s request to raise annual base distribution rates by approximately $70 million. The decision, originally slated for July 1, will be pushed to November, Lembo said.
PSNH implemented a temporary $28 million rate increase effective July 1, 2019, which will remain in effect until permanent rates are set. Any difference between the temporary rates and the permanent rates will be reconciled back to that July time frame.
In Massachusetts, the company’s NSTAR gas subsidiary is seeking a $38 million base rate adjustment, having agreed to a one-month delay with a decision now expected at the end of October and rates effective on Nov. 1, Lembo said.
In addition, a new three-year grid modernization work plan for 2021-2023 will be filed in Massachusetts this summer, and Connecticut regulators on Wednesday issued an order requesting proposals on program designs for a number of initiatives related to grid modernization, with proposals due by the end of July, he said.
Sailing Close to the Wind
Eversource’s offshore wind energy partnership with Ørsted on March 13 filed a construction and operations plan (COP) with the Bureau of Ocean Energy Management for the 704-MW Revolution Wind project.
“BOEM’s review of that project has begun, and we expect to have a full schedule for that review later this year,” Lembo said. (See Offshore Wind Slogs Forward in Massachusetts.)
Proposed routing of the South Fork Export Cable from Deepwater Wind’s COP filing | Deepwater Wind
“We have not yet received a new schedule from BOEM on its review of the 130-MW South Fork project. The COP on that was filed back in 2018, but the process was paused last year so that we could update the project for our new 1-nautical-mile-by-1-nautical-mile configuration. We expect the new schedule to be posted by midyear.”
The companies last October signed a contract with New York for the 880-MW Sunrise Wind offshore wind project, but even with the 10-week delay in the review ordered by the state’s Public Service Commission, the developer still expects the project to come into service by the end of 2024.
“We continue to have a target filing date on our COP for Sunrise Wind with BOEM in the second half of this year,” Lembo said. “That timetable may be affected by New York’s current restrictions on both onshore and offshore survey work. We expect to have more insight into the timing of that cost filing and the schedule for Sunrise by late this summer.”
Eversource expects South Fork to come into service by the end of 2022, and Revolution Wind by end-2023, he said.
“Despite these near-term scheduling headwinds, we remain strongly convinced that the opportunities in offshore wind off the Northeast coast are excellent, with 15,000 MW likely to be built over the coming years to supply the significant clean energy needs of New England and New York,” Lembo said.
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.”
