Page 1098 – RTO Insider

May 10, 2020

PPL Reaffirms 2020 Financial Targets Despite Pandemic

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.

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.”

May 10, 2020

Con Ed Q1 Earnings down on Virus, Weather

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%.

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.

May 10, 2020

MISO Leans Toward Seasonal RA

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.

MISO Seasonal RA — 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.

May 10, 2020

Eversource Q1 Earnings Unfazed by Pandemic

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.

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.)

“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.

Call transcript courtesy of Seeking Alpha.

May 8, 2020March 11, 2025

Sagging Demand Cushions NPCC’s Summer Outlook

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 Summer Outlook — 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.”

May 8, 2020

CPUC, PG&E Agree to Record $1.9B in Penalties

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.

CPUC PG&E Penalties — Commissioner Clifford Rechtschaffen | © *RTO Insider*

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.

May 8, 2020January 28, 2024

Enable Losses Slam CenterPoint, OGE Energy

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.

May 8, 2020

NRG’s Q1 Retail Earnings Stave off COVID Declines

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.”

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.”

Call transcript courtesy of Seeking Alpha.

May 8, 2020

PJM, IMM Present MOPR Rules for State Procurements

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

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

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

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

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

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

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

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

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

PJM Straw Proposal Approach

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

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

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

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

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

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

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

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

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

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

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

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

IMM Alternative

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

PJM Monitor Joe Bowring | © *RTO Insider*

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

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

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

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

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

May 7, 2020

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

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

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

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

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

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

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

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

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

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

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

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

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

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