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November 14, 2024

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Con Edison Q3 Earnings up on Clean Energy Growth

Consolidated Edison (NYSE:ED) on Thursday reported 2021 third-quarter net income of $538 million ($1.52/share), up 9.1% compared with $493 million ($1.47/share) in the same period a year ago, citing strong performance in its Clean Energy Businesses unit.

For the first nine months of 2021, net income for common stock was $1.122 billion ($3.23/share), an increase of 6% compared with $1.058 million ($3.17/share) over 2020.

“Our energy systems delivered world-class reliability this summer. In response to several storm events and heat waves, our team efficiently restored affected customers and are managing the costs of these efforts,” CEO Timothy Cawley said in a statement.

Protecting customers from climate change makes the company’s integrated planning and clean energy investments more critical than ever, he said.

“We continue to lead the transition to a clean energy future, evidenced during the quarter by our solicitation for large energy storage projects, which will allow our customers to maximize the benefits of renewable energy,” Cawley said.

The company reported its Clean Energy Businesses having 3,004 MW of utility-scale renewable energy production projects in service (2,988 MW) or in construction (16 MW), and 72 MW of such projects behind the meter in service (62 MW) or in construction (10 MW). The business unit generated 1,932 kWh of electricity from solar projects for the three months ending Sept. 30, up nearly 16% compared to 1,667 kWh for the same period in 2020.

Rate plans for investor-owned utilities in New York allow them to defer costs resulting from a change in legislation, regulation and related actions that have taken effect during the term of the plans once the costs exceed a specified threshold. The total reserve increases to the allowance for uncollectible accounts from Jan. 1, 2020, through Sept. 30 — reflecting the impact of the COVID-19 pandemic for Consolidated Edison Company of New York (CECONY) electric and gas operations and Orange and Rockland Utilities (O&R) electric and gas operations — were $235 million and $7 million, respectively.

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NYISO Looks at Capacity Market Change Cost Impacts

The cost impacts of proposed wholesale capacity market changes topped the agenda of NYISO’s Installed Capacity (ICAP) Market Issues Working Group on Tuesday.

NYISO discussed the methodology used to measure the market impacts of implementing changes to buyer-side mitigation (BSM) rules, while the ISO’s Market Monitor, Potomac Economics, presented an analysis of the effects of capacity accreditation on consumers.

In 2026, capacity market procurement costs would be approximately $5 million below the status quo case using an average accreditation approach, while costs would be $119 million lower using the marginal accreditation approach proposed by the NYISO, Tariq N. Niazi, NYISO senior manager for consumer impact analysis, told the ICAP group.

The ISO is developing a proposal to help keep the capacity market just and reasonable as thousands of megawatts of state-solicited resources come online in New York. The Climate Leadership and Community Protection Act (CLCPA) requires the state to procure large amounts of renewable energy to get to zero-emission electricity by 2040, forcing the wholesale electricity market to adapt.

Several stakeholders forced some new business to the top of the agenda regarding BSM, asking the ISO to explain a request from the Price Responsive Load Working Group for information from demand response (DR) curtailment providers.

The issue stems from NERC and FERC analysis focused on the effect of load-management and load-shed programs on fuel supply infrastructure.

The NERC Standards Committee last month voted to delay approving the draft standard authorization request (SAR) developed in response to a preliminary joint report with FERC on the catastrophic winter storm events in Texas last February until after the final report is published. (See NERC Standards Committee Delays Action on Cold Weather SAR.)

The ISO is working on the issue, Zachary Smith, manager for capacity market design, said. In response to stakeholder interest in DR related to the Comprehensive Mitigation Review, the Analysis Group will be available at the Nov. 8 ICAP Working Group to answer question.

One stakeholder asked whether NYISO considers the study assumptions for DR differently from special case resources, which require a 21-hour notice before dispatch.

“I think we’re looking for false precision in the analysis that we’re doing,” Michael DeSocio, NYISO director of market design, said. “We’re not running an economic expansion analysis here. The analysis is intended to indicate directionally what would happen. The analysis we’ll see from Potomac goes a step further, but again there are limitations on how granular we’re able to get in these analyses.”

Accreditation: Consumer Impact

A marginal accreditation approach results in more efficient signals for investment and lower consumer costs than the status quo or an average approach, Joe Coscia of Potomac Economics said.

Intermittent-Renewable-Capacity-(Potomac-Economics)-Content.jpgMarginal accreditation encourages a balanced mix of intermittent.renewables compared to other approaches. | Potomac Economics

Capacity market signals can help guide investment in policy resources at the lowest cost to consumers when renewable energy credits supplement wholesale market revenues, the analysis said.

Efficient accreditation will have more impact as the CLCPA requires larger quantities of investment, and the Monitor supports NYISO’s proposal to apply a marginal accreditation approach to all resources, Coscia said.

“You can’t look at these capacity credit numbers in a vacuum. They are always a product of the resource mix in the case being studied,” he said.

Stakeholders have asked about the period beyond 2030 that Potomac was not able to model explicitly in this study, prompting Coscia to share thoughts on factors that would intuitively tend to affect the results going forward, given the logic of the model.

“All of these things in the context of our model would tend to increase the divergence between accreditation methods going forward,” Coscia said. “Those include larger renewable and storage targets, and the reason would be that with more investment decisions that need to be made, the cost of making inefficient investment decisions is larger.”

Any policy requiring replacement of a larger measure of peaking resources would tend to increase the importance of accreditation, he said.

Consumer savings under a marginal approach would be greater at higher capacity prices because the differences in capacity payments would be magnified, which affects both the incentive effects as well as the total payment differences between methods, Coscia said.

“Higher load growth or changes in load pattern would tend to increase the importance of efficient accreditation, whether that’s just high load going forward or maybe something like a shift towards a winter peaking system,” he said.

Finally, application of enhanced accreditation methods to other technologies such as gas-only units or inflexible units would tend to produce values for those resource types that would decline more under a marginal approach than under an average approach or the status quo, which doesn’t apply any discount to those resources — also increasing the consumer savings under a marginal approach.

“For these reasons we believe that the advantage of marginal accreditation over other methods is likely to increase beyond 2030, and so the numbers that we presented here likely are conservative,” Coscia said.

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California PUC Approves More Gas at Aliso Canyon

Concerned about a shortage of natural gas this winter, the California Public Utilities Commission on Thursday made the controversial decision to increase the maximum amount of gas stored at the troubled Aliso Canyon underground facility by more than 7 billion cubic feet.

The unanimous decision came after nearly two hours of public testimony, much of it emotional, from residents who live near the site of one of the worst methane leaks in U.S. history. From October 2015 to February 2016, a ruptured pipe at the SS-25 well spewed more than 100,000 tons of natural gas into the atmosphere, leading to a blowout. The leak was contained after four months and multiple failed attempts.

“My family and I still suffer daily from the physical and mental health effects of the Aliso Canyon blowout,” Dan Labudas, a resident of the adjacent Porter Ranch community, told the commissioners. “Back in 2015, when the leak occurred, we suffered from nosebleeds, stomach aches, headaches, nausea and other physical and mental ailments. The four months it took to seal the leak were some of the most stressful and devastating months for my family and community.”

The ailments Labudas described were common to many residents living near the facility. In late September, SoCalGas and its parent company Sempra Energy agreed to pay $1.8 billion to settle the claims of 35,000 victims of the leak.

Labudas on Thursday urged the CPUC to deny any increase in storage limits and to shut down Southern California Gas Co.’s sprawling underground facility, a main gas supply for the Los Angeles Basin.

The CPUC’s original proposed decision called for increasing Aliso Canyon’s storage limits from 34 billion cubic feet to nearly 69 billion cubic feet. Commissioner Martha Guzman Aceves offered an alternative that would allow an increase to just over 41 billion cubic feet, enough to ensure reliability this winter for ratepayers in Southern California, she said.

The decision is “very limited to the winter interim storage levels,” Guzman Aceves said.

Unpredictable weather and a strained gas supply this year made the measure necessary, she said.

“For a good year-and-a-half now, we have seen the very high fluctuations in our changing climate that many of us thought would be unlikely in the past,” Guzman Aceves said. “The extreme weather events have become more and more likely. The extreme heat in the state and the continued drought has greatly impacted the availability of hydroelectricity and, unfortunately, has created greater short-term dependency on natural gas generation. And of course, in addition to extreme heat, there’s the potential for the other extreme, and that is the cold winter.”

Some public commentors mentioned February’s Texas deep freeze and widespread power outages, Guzman Aceves noted. California was fortunate to be having a warm winter at the time but “if we were to get one of those events again this winter, and California was experiencing cold winter days at the same time as the rest of the West,” it could create reliability concerns and the possibility of curtailments, she said.

The CPUC is in a multi-phase process of studying the effects of closing Aliso Canyon and the alternative resources needed to compensate; the latest in a series of workshops was held Wednesday. Guzman Aceves, the assigned commissioner in the effort, said the CPUC remains committed to decommissioning Aliso Canyon or limiting its role.

“Our decision today helps ensure energy reliability for the Los Angeles Basin this winter in a safe and reliable manner,” she said in a statement following the vote. “We continue to move forward on planning how to reduce or eliminate the use of Aliso Canyon, and to ultimately reduce our reliance entirely on such natural gas infrastructure as we transition to a clean energy economy.”

California’s two Democratic senators, Dianne Feinstein and Alex Padilla, earlier this week called for the permanent closure of Aliso Canyon “to protect the safety of Californians.”

“It is critical that the California Public Utility Commission outline concrete steps to close this facility while ensuring the reliability of our power grid as we continue the transition to cleaner electricity, heating and cooling,” Feinstein and Padilla said in a joint statement.

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PJM PC/TEAC Briefs: Nov. 2, 2021

Planning Committee

Winter Weekly Reserve Target Endorsed

PJM stakeholders unanimously endorsed the results of the 2021/22 winter weekly reserve target analysis at Tuesday’s Planning Committee meeting.

Patricio Rocha Garrido, of PJM’s resource adequacy planning department, reviewed the results of the analysis, saying the numbers differed slightly from 2020/21 because of more uncertainty in the modeling. Rocha Garrido first presented the analysis numbers at last month’s PC and Operating Committee meetings. (See “Winter Weekly Reserve Target Update,” PJM Operating Committee Briefs: Oct. 7, 2021.)

Members also unanimously endorsed the analysis at Thursday’s OC meeting.

The targets for December, January and February are 24%, 27% and 21% respectively, compared to 23%, 27% and 23% last year. Rocha Garrido said the December value increased slightly because PJM sees more load uncertainty in the modeling, while February’s decrease is a result of less load uncertainty.

PJM staff use the targets, which are part of the reserve requirement study, to help coordinate planned generator maintenance scheduling over the winter months. Rocha Garrido said the purpose of the targets is to “cover against uncertainties” related to load and forced outages, ensuring that the loss-of-load expectation (LOLE) for winter is “practically at zero.”

The winter weekly reserve target for each month is the highest weekly reserve percentage, rounded up to the next integer value. Rocha Garrido said the targets are only recommendations to PJM’s operations department.

Manual Endorsements

Several manual updates stemming from the biennial cover-to-cover review also won unanimous stakeholder endorsement. The updates were first presented at the October PC meeting. (See “Manual First Reads,” PJM PC/TEAC Briefs: Oct. 5, 2021.)

Michael Herman, of PJM’s transmission planning department, provided a review of Manual 14B: PJM Region Transmission Planning Process Update, including the addition of a new section that features details around the incorporation of end-of-life (EOL) needs in the Regional Transmission Expansion Plan, which were part of the tariff attachment M-3 discussions.

FERC in December rejected a stakeholder proposal to move EOL projects under PJM’s planning authority, siding with transmission owners who argued that it would violate their rights. (See FERC Rejects PJM Stakeholder EOL Proposal.) The commission also accepted the TO sector’s tariff amendments concerning EOL projects in August 2020, rejecting arguments in rehearing requests by more than a dozen load-side stakeholders. (See FERC Accepts PJM TOs’ End-of-life Revisions.)

John Reynolds, of PJM’s resource adequacy planning department, reviewed minor changes to Manual 19: Load Forecasting and Analysis. Reynolds said the most significant change was adding battery storage to the list of forecasted items in the load forecast model overview in Section 3.1, which already includes distributed solar generation, plug-in electric vehicles and historical weather patterns to estimate growth in peak load and energy use.

Joseph Hay, of PJM’s infrastructure coordination department, reviewed the updates to Manual 14F: Competitive Planning Process, saying the changes were necessary to correct the proposal fee structure in the manual to conform to the Operating Agreement.

Hay said the language in Manual 14F was not in agreement with the latest changes to the OA, which states, “All proposals in any RTEP window are subject to a nonrefundable deposit of $5,000, except for project proposals submitted with cost estimates of $5 million or less. In addition to the $5,000 nonrefundable deposit, the proposing entity must pay all actual costs incurred by PJM to evaluate the submitted project proposal.”

The manual changes now go to the Nov. 17 Markets and Reliability Committee meeting for endorsement.

Transmission Expansion Advisory Committee

Generation Deactivation Notification

Phil Yum of PJM provided an update on recent generation deactivation notifications.

PJM has received a “good amount” of deactivation requests in the last month in the PPL transmission zone, he said. Those requests include:

  • Williamsport CT 1 and 2 oil-fired units, with a total of 26.6 MW of generation;
  • West Shore CT 1 and 2 oil-fired units, 28 MW;
  • Lock Haven CT 1 oil-fired unit, 14 MW;
  • Jenkins CT 1 and 2 oil-fired units, 27.6 MW; and
  • Fishbach CT 1 and 2 oil-fired units, 28 MW.

The requested deactivation date for these units is April 1, 2022.

Several other units in the PPL transmission zone have a requested deactivation date of June 1, 2022. Those units include:

  • Martins Creek CT 1, 2 and 3 oil-fired units, 57.3 MW;
  • Harrisburg CT 1, 2 and 3 oil-fired units, 41.1 MW; and
  • Allentown CT 1, 2, 3 and 4 oil-fired units, 56 MW.

Four different units in the Dominion transmission zone were also added to the deactivation list, with a requested date of June 1, 2023. They include:

  • Rockville CT diesel unit, 4 MW;
  • Lanier CT 1 diesel unit, 7 MW;
  • Dinwiddie CT 1 diesel unit, 3 MW; and
  • Weakley CT diesel unit, 7 MW.

A reliability analysis was completed for all units, and no violations were identified.

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World Economic Forum Working to Transition Industrial Clusters to Net Zero

The World Economic Forum, in collaboration with consultancy Accenture and the Electric Power Research Institute (EPRI), on Wednesday launched a new initiative to transition so-called “industrial clusters” toward net-zero emissions.

Industrial clusters are geographic regions with co-located industrial customers. Such regions account for approximately 15 to 20% of global CO2 emissions, according to EPRI.

“We believe these clusters are one of the most impactful areas when it comes to achieving our net-zero emissions,” said Louise Anderson, electricity industry manager at World Economic Forum.

Companies that are co-located can take advantage of synergies in order to accelerate their progress toward net zero, she said. The initiative advances the work being done to accelerate the deployment of hydrogen and other low-carbon technologies, including those for electrification and efficiency, Anderson said.

The initiative has already recruited two clusters in the U.K. and one each in Australia and Spain, with a collective CO2 emissions reduction profile of approximately 30 million tons. It aims to have 100 industrial clusters signed up by 2024, but hopefully it can do a lot more than that, said Melissa Stark, global renewables and energy transition lead at Accenture. “One hundred clusters could be 800 million tons; that’s like Germany” alone, she said.

Twenty years ago industry managers were told that decarbonizing the power industry was very difficult; that renewables were just a small part of the effort; and that decarbonizing heavy industry was nearly impossible, said Agustin Delgado, chief innovation and sustainability officer for Iberdrola, representing the participating cluster in the Basque region of Spain.

“We want to prove with these industrial clusters that it can be done,” Delgado said. “We can start today delivering low-heat industrial processes, electrification of some of the processes and using new materials like green steel.”

Such environmental targets by industry bring good business value, sustainable impact and create new jobs, Anderson said, citing U.K. hopes to secure 1.5 million jobs by developing four net-zero industrial clusters, which through avoided emissions can also bring the country 3 billion to 4 billion pounds of potential savings per year by 2050.

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Last-minute Unease over MISO’s Seasonal Accreditation

MISO stakeholders remain apprehensive about the RTO’s plan to hold four seasonal capacity auctions with separate reserve margins before the 2023-24 planning year, less than a month before it gets FERC scrutiny.

Nearly all their concerns can be traced to a seasonal capacity accreditation based on a generating unit’s past performance during tight conditions.

During a Resource Adequacy Subcommittee call Wednesday, Entergy’s Wyatt Ellertson said the accreditation design seems poised to raise several of MISO’s local resource zones to the cost of new entry (CONE), which currently stands around $257/MW-day. He asked the grid operator to give members more time to prepare for the changes.

“What I haven’t heard you say is this proposal doesn’t reflect reality,” MISO Director of Resource Adequacy Coordination Zakaria Joundi responded. He said staff is not trying to avoid or achieve CONE pricing in its capacity auction.

In September, MISO leaders gave stakeholders an extra 60 days to digest the proposal. Several stakeholders have said they’re incredulous that a seasonal paradigm will improve system reliability. (See MISO Extends Seasonal Auction Discussions.)

Staff has said a FERC filing will be made no later than Dec. 1.

Kevin Vannoy, MISO’s director of market design, said awarding a greater accredited capacity value to generators that consistently show up when they’re needed the most should boost reliability.

“Over time, that will incentivize resources to be available during the time of tightest needs, so that in turn incentivizes reliability,” he said.

Independent Market Monitor (IMM) Michael Chiasson said it’s only appropriate for a local resource zone stocked with slow, inflexible resources to receive lower accreditations and force the zone to procure additional resources.

Stakeholders asked whether MISO has a plan to alter its accreditation if its resource adequacy outlook improves and it is again flush with reserves. Some said staff was pessimistic to assume that the RTO would always have tight operating conditions as a basis for capacity accreditation.

“We may have to add provisions if we never have less than a 25% reserve margin,” Vannoy said. However, he said even three years without a single maximum generation event isn’t a guarantee that MISO won’t experience tight operating conditions during an upcoming year.

“That’s a high-class problem to have,” MISO’s Scott Wright said.

Coalition of Midwest Power Producers representative Travis Stewart said the RTO’s sustained increase in maximum generation events and emergency actions in “mild system conditions” means that utilities might need to update integrated resource plans and prioritize some generation projects.

“There’s indication of a big issue even if the Planning Resource Auction is printing low prices,” Stewart said.

He pointed out that MISO’s Monitor has long maintained that the capacity auction doesn’t reflect the true marginal value of capacity.

Staff has warned that threat of a maximum generation emergency exists on any given day due to increased use of intermittent resources and an aging baseload fleet that’s more prone to outages. In spite of system load around 70 GW and mild weather, MISO entered conservative operations and a maximum generation alert Oct. 4 in its Midwest region because of planned and unplanned generation outages.

Bill Booth, consultant to the Mississippi Public Service Commission, asked whether MISO is furnishing specific accreditation numbers for individual generators.

Joundi said staff has reached out to members about certain generators’ value. He cautioned that MISO doesn’t have the resources to produce outputs for a large load-serving entity’s entire fleet.

The grid operator will also impose a 31-day limit on planned generation outages in any season before capacity resources must procure replacement capacity. The IMM will also consider requests from generators to be excluded from auction participation, even if it will be uneconomic for units to offer into the auctions.

Ellertson asked MISO to provide the numbers of generators not participating in the auctions due to the 31-day outage threshold.

Minimum Capacity Requirement Exits Filing 

MISO will file separately with FERC a minimum capacity requirement request in which members must demonstrate that at least 50% of capacity needed to meet their peak load is secured ahead of the voluntary capacity auction.

MISO had originally intended to include the rule in its seasonal capacity filing.

“We’ve been receiving a lot of feedback from stakeholders indicating that we need to separate [a capacity demonstration] from seasonal accreditation,” MISO counsel Michael Kessler told stakeholders during an October Resource Adequacy Subcommittee meeting. “We’ve had a lot of internal discussions regarding our best chances for success at FERC.”

The Organization of MISO States said it supported removing a minimum capacity obligation from MISO’s first filing.

Members Ask for 3 Filings

Some MISO members don’t think the filing split goes far enough. DTE Energy asked staff to further divide the plan into three separate filings for the seasonal auctions, minimum capacity requirement, and the availability-based accreditation. DTE also asked that the RTO hold off on the accreditation component until it more fully addresses stakeholder concerns.

The utility maintains that the auction and accreditation design hasn’t been fleshed out with stakeholders and continues to evolve late in the process.

Members Consumers Energy, Entergy, Madison Gas and Electric, Michigan Public Power Agency, Southern Minnesota Public Power Agency and WPPI Energy joined DTE in the ask.

“Now that it’s been split once, it’s doable to split it again,” DTE’s Eric Bidlingmaier said. “Doing so will allow stakeholders to better support or oppose any component of the filing and allow each aspect of the proposal to be evaluated on its own merits.”

Bidlingmaier said MISO is attempting to “fundamentally re-engineer nearly every aspect of its resource adequacy construct in a way that no other U.S. RTO has ever undertaken.”

Some stakeholders said a three-way split of the filing would provide greater assurance that MISO could implement parts of the plan, instead of having a comprehensive design rejected by FERC.

Customized Energy Solutions’ Ted Kuhn said he didn’t view the members’ ask as “obstructionist,” but rather as a plea for staff to propose a better accreditation design.

Wright said he didn’t see the request as obstructionist either, but he said MISO views the seasonal auction and accreditation as going hand-in-hand. He noted that the RTO has already granted a delay request by stakeholders and will move ahead with the filing at the end of the month.

During OMS’s annual meeting Oct. 28, North Dakota Commissioner Julie Fedorchak said she was at odds with her state’s utilities for her support of “starting to hold resources accountable” for their availability.

“I personally am comfortable with this,” Indiana Utility Regulatory Commissioner Sarah Freeman said, adding it was imperative that MISO values a resource’s contribution accordingly.

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Eversource Warns of Higher Winter Bills as Gas Prices Bounce Back

Eversource Energy on Wednesday warned that customers will likely see a spike in their electricity and gas bills this winter compared to last year’s, as natural gas prices surge nationwide.

During a call with investors Wednesday to discuss its third-quarter earnings, Eversource CFO Philip Lembo said that starting in January ratepayers in Connecticut and Massachusetts will likely see a 2- to 3-cent/kWh rate increase on their bills, which translates to an additional $20 to $25/month on a typical bill. Gas customers can expect an increase of about $30. New Hampshire rates remain in effect until February.

Energy prices hit 10-year lows in 2020 amid the COVID-19 pandemic. Because of wintertime natural gas constraints in New England, ratepayers usually see up to a 2-cent/kWh increase in January that often reverses by the summer, but gas prices have risen significantly since the beginning of the year, driven by an increase in global demand during the ongoing economic recovery and a significant drop in U.S. gas supply. Between Oct. 20 and 27, natural gas spot prices rose from $4.79/MMBtu to $5.86/MMBtu, according to the most recent weekly report from the U.S. Energy Information Administration. At the Algonquin Citygate, which serves Boston-area consumers, the price went up from $4.52/MMBtu to $5.65/MMBtu.

Isaias Settlement

The earnings results came on the heels of last week’s announcement of an approved settlement over penalties and return on equity reductions levied on the utility for its handling of Tropical Storm Isaias in August 2020. The settlement will provide $65 million in bill credits and $10 million for low-income assistance programs.

“Settling critical regulatory and legal disputes was a necessity to reset our relationship with key Connecticut stakeholders,” Eversource CEO Joe Nolan said. “We all want the state to move ahead on addressing critical energy and climate issues, and the outstanding disputes have the potential to delay some of this important work.”

Before the settlement, Eversource would have been set to lose more than $150 million based on the penalties and ROE cuts thanks to the Take Back Our Grid Act, which directed the Public Utilities Regulatory Authority to develop and implement performance-based regulations including financial penalties and ROE reductions.

In a rare dissent, PURA Chair Marissa Gillett said that “more devastating storms” like Isaias “will come to pass,” and tools such as an ROE reduction “would more acutely encourage Eversource’s executives to properly prepare for and respond to such storms.” Gillett also said she was “apprehensive of a future where we still do not have a court-backed interpretation of PURA’s regulatory authority in holding utilities accountable following a storm event.”

State Rep. David Arconti (D), co-chair of the General Assembly’s Energy and Technology Committee, told RTO Insider that Eversource “may want to move forward, but I’m not necessarily there yet.”

Arconti said the Lamont administration, like previous administrations, had a predisposition to settle, but “there are some cases where I think it’s worth it to go to the mat.”

“I do think the settlement is just more par for the course and kind of perpetuates some of the norms on how we’ve gotten to where with certain things,” Arconti said.

When the average person looks at the settlement, they will not understand why specific rates are frozen and other areas are increasing on their bills, he said. “It doesn’t help us do our job when the people see stuff like that.”

Earnings

Eversource reported earnings of $283.2 million ($0.82/share), down from $346.3 million ($1.01/share) for the same period in 2020. The company’s transmission segment earned $139.4 million in the quarter, nearly $14 million more than last year’s. Eversource attributed the increase to higher level of investment in its infrastructure.

Call transcript courtesy of Seeking Alpha.

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Duke Touts Clean Energy Progress, Strong Earnings in Q3

Duke Energy CEO Lynn Good spent most of Thursday’s third-quarter earnings call talking about the progress the utility has made on its climate goals and clean energy transformation, such as cutting emissions more than 40%, accelerating the closure of coal plants and launching a new sustainable financing initiative for “green and social projects.”

Duke will finance a range of clean energy projects — non-hydro renewables, energy efficiency and storage — via bonds, loans or commercial paper, according to a report on the initiative released Tuesday. Nuclear projects will not be eligible, and the utility has pledged to provide transparency with a website that will track the money it allocates to projects and their environmental impacts.

Spokesperson Meredith Archie said Duke has financed $2.3 billion in projects with green bonds since 2018, but the utility has not committed to any specific spending targets for the new initiative. Rather, the initiative will be part of Duke’s capital expenditures, which, Good said, are expected to grow from $59 billion for 2021-2025 to $65 billion to $75 billion by 2029.

“As we look ahead, our pace of change will accelerate as we work toward our carbon reduction goals and the broader clean energy transformation across all of our jurisdictions,” Good said.

According to information in the Q3 slide deck for the call, the utility sees 50% of its capital spending going to transmission and distribution investments in resiliency and a “green-enabled” grid and another 20% to renewable projects.

The passage of House Bill 951 in North Carolina in October has upped the ante for Duke, which had originally committed to cutting its carbon emissions 50% by 2030, on the way to achieving net zero by 2050. A bipartisan compromise, the new law mandates a cut of 70% over 2005 levels by 2030, while keeping the 2050 goal for net-zero. (See NC Compromise Energy Bill Passes Senate, Heads Back to House.)

The law gives the North Carolina Utilities Commission (NCUC) the primary responsibility for developing a carbon reduction plan, to be reviewed every two years, with utility and stakeholder input. But Good clearly sees Duke as having a major role in shaping the plan, which she said will be “approved” by the commission and will draw on “the conversations that have been ongoing over the last several years.

“We anticipate the active involvement of South Carolina in this process as they have been over the decades in developing and retiring assets that serve both states,” Good said.

The law also gave Duke a major win with its authorization of performance-based regulation and multiyear rate plans. Under the law, Duke will have to hit certain performance targets, to be set by the NCUC, but will be able to file a three-year rate plan under which, once approved, the utility will be able raise rates up to 4% in each of the subsequent two years without submitting an annual rate case, as it does now.

CFO Steve Young cited the multiyear rate plan as one of several growth drivers for Duke, and he said 2022 would be a “key year” for the rule making needed to implement HB 951 and the carbon reduction plan.

Young reported third-quarter unadjusted earnings of about $1.37 billion ($1.79/share), up from $1.27 billion ($1.74/share) a year earlier. Adjusted earnings per share were $1.88, a penny over the adjusted earnings of $1.87 per share a year ago.

Another growth driver in the quarter was a bounce-back in electricity demand, especially in the commercial and industrial sectors as the economy recovers from the COVID-19 pandemic and people return to offices, Young said. Residential retail sales took a small 0.2% dip, but overall electricity sales were up 3.4% for the quarter, he said.

Shift Away from Coal

Other green initiatives highlighted by Good included a “low-income collaborative to propose new low-income programs to further help our customers.” Archie said the initiative would bring in consumer advocates and other stakeholders to look at rate design, energy efficiency programs and other measures to cut bills for low-income customers.

Good also talked about Duke’s accelerated coal retirements, as laid out in the utility’s revised integrated resource plans for Duke Energy Carolinas and Duke Energy Progress, submitted to the South Carolina Public Service Commission in August. The commission earlier this year rejected Duke’s original plan, which kept more than 3,000 MW of coal-fired generation online through 2038; the revised plan would retire all coal by 2035.

In North Carolina, the utility has retirements planned for three units totaling 677 MW at its Allen Steam Station, one already offline and the other two by the end of the year, Archie said. Another 280-MW of coal fired-generation in Indiana has also come offline this year, she said.

Good expects the revised plans for South Carolina to be approved by the end of the year; the utility’s IRPs are still pending before the NCUC. She also noted that Duke Indiana will be submitting its IRP by a Nov. 30 filing deadline. While she said the IRP “will continue to advance efforts to shift away from coal,” she did not provide further details. Information on the utility’s website sets 2048 as the retirement date for Duke’s final coal plant in Indiana.

Responding to an analyst question, Good also aligned Duke’s clean energy transition with the clean energy provisions in the bipartisan infrastructure plan and the budget reconciliation bill still in negotiation in Congress.

The utility is seeing “conversation” around the clean energy transition across its service territories in the Carolinas, Indiana and Florida, she said. “You see increasing opportunities for renewable investment, for storage investment, energy efficiency, demand response investment … some of our states also have a keen interest in getting a base amount of electric vehicle infrastructure in place.”

Although not mentioned during the call, Duke and Honeywell recently announced that the utility will be testing a new, long-duration flow battery technology developed by the tech company to provide flexibility and backup power for renewables.

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NERC Board of Trustees/MRC Briefs: Nov. 4, 2021

Hybrid Meetings to Start in February

After nearly two years of holding meetings online amid the COVID-19 pandemic, NERC Board Chair Ken DeFontes finally confirmed that the organization’s Board of Trustees and Member Representatives Committee (MRC) will return to in-person gatherings at their next session in February 2022.

Speaking at Thursday’s virtual open meeting of the MRC, DeFontes previewed the preliminary plans for next year’s meeting schedule. As NERC’s management has hinted on previous occasions, February’s meetings will be held in a hybrid format, with the board and MRC gathering in person and all other attendees joining virtually. While the February meeting had been planned for New Orleans, DeFontes said this session will take place at NERC headquarters in Atlanta to ensure a big enough meeting space and appropriate equipment for the online stream.

While the schedule for the remainder of the year has not been finalized yet, DeFontes said the board is planning for the May and August meetings to be in-person gatherings in D.C. and Vancouver, Canada, without an online component. The location and format of the November meeting are yet to be determined, but it will likely be another hybrid gathering.

“I think in the long run, [we’re] probably going to end up with two full, in-person meetings and two hybrid-type meetings” per year, DeFontes said. “We’ll see how that goes. I’m very optimistic that we’ll be able to do this, and I think everybody I speak to is really starving for the opportunity to get back together and continue to have the informal conversations and see people in person.”

Frustration at Cold Weather Delay

The decision of NERC’s Standards Committee last month to delay approving for industry comment a standard authorization request (SAR) developed in response to February’s winter storm drew sharp words from several attendees at Thursday’s board meeting.

Jim-Robb-(NERC)-Content.jpgNERC CEO Jim Robb | NERC

“I was really disappointed that the … committee didn’t take action in October,” NERC CEO Jim Robb said. “When I informed the FERC chairman of the Standards Committee’s inaction, the only way I could describe his reaction was one of befuddlement and disbelief.”

The SAR was drafted after FERC and NERC released their preliminary report on February’s storms, which listed nine key recommendations for avoiding another near complete collapse like the one experienced by ERCOT, in September. (See FERC, NERC Share Findings on February Winter Storm.)

Committee members were reluctant to authorize the new SAR without seeing the final report. (See NERC Standards Committee Delays Action on Cold Weather SAR.) However, Robb reminded the committee on Thursday that they were only being asked to send the SAR for comment, not to approve moving forward with standard development.

“This was just a step to … get the process started, so we can begin to work on a very complicated matter of significant importance,” Robb said. “We can’t use the process or, worse, fear of compliance to delay dealing with issues.”

DeFontes too expressed “disappointment” in the committee’s inaction, calling the “social and economic costs” of the February storms “significant” and emphasizing that the threat of cold weather toward the electric grid continues to grow.

“The board understands the desire to approach these issues in a deliberate and measured manner. The joint inquiry team recommendations call for some dramatic adjustments in how the industry approaches winter preparation,” DeFontes said. “In our opinion, these adjustments are not only dramatic, but also vitally and urgently necessary. The way we do that is by taking on these issues directly and expeditiously.”

Standards Committee Chair Amy Casuscelli, of Xcel Energy, assured the board that “the committee understands the urgency and wants to be responsive … as expeditiously as possible.” She promised prompt action once the final report is released, which is expected some time this month.

Jones, Flandermeyer Picked to Head MRC

MRC members unanimously elected Vice Chair Roy Jones, CEO of ElectriCities, to succeed Paul Choudhury of BC Hydro as chair for 2022. Evergy’s Jennifer Flandermeyer will take over from Jones as vice chair. Their terms begin in February.

Nominations for a special election to fill Flandermeyer’s role as representative of sector 1 (investor-owned utilities) will begin Nov. 5 and conclude Dec. 3, with the election to be held Dec. 13-22. Choudhury reminded members that regular elections for representatives whose terms expire in February will take place from Dec. 8 to 17; nominations for those elections opened Sept. 8 and will end on Monday.

Trustees and Members Honor Gallagher

Both the board and the MRC passed a resolution honoring Bill Gallagher, formerly of the Vermont Public Power Supply Authority, who died Oct. 15 in Florida. At the time of his death, Gallagher had served on the MRC since its inception in 2007, including stints as its vice chair on 2010 and chair in 2011.

In addition to his service at NERC, Gallagher’s resume included time as chairman of the American Public Power Association (APPA) and general manager of Vermont Electric Cooperative. According to Gallagher’s obituary, he spent the last several years serving as a consultant for the Transmission Access Policy Study Group.

“I know if we were [together] in person, we’d be using almost all of our coffee breaks and in-between time to talk about Bill and the memories he’s had for each of us,” Choudhury said. “I only knew Bill for a few years, but for many of you, Bill has been a big part of your own participation here at NERC. … Bill was always there and ready with some really good questions for us. So let’s honor his legacy by being Bill today and asking great questions.”

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NERC Shelves 2022 Atlanta Relocation Plans

NERC has nixed its goal of relocating its Atlanta office in 2022 after failing to negotiate a lease at the planned new location, CFO Andy Sharp said Wednesday.

Speaking at the November open meeting of NERC’s Finance and Audit Committee, Sharp said the organization was “not able to reach a mutual agreement” with the prospective landlord. NERC’s Board of Trustees gave permission in September for management to sign the lease for the new office and to amend its 2022 Business Plan and Budget to cover moving costs. (See NERC Board Approves Atlanta Office Move.)

NERC had planned to exercise the early termination clause in the lease for its current office in the Atlanta Financial Center, allowing the organization to leave the space by October 2022. Last month NERC received FERC’s approval to spend up to $2 million from its Operating Contingency Reserve to pay the fee for exercising the clause (RR20-6). (See FERC Approves Funding for NERC Office Move.) With the move canceled, NERC will stay at the Atlanta Financial Center until its lease ends in October 2025.

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Andy Sharp, NERC

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The new office location — which NERC’s management has not publicly revealed, citing the ongoing negotiations — would have charged significantly lower rent and offered several attractive amenities such as free employee parking and convenience to transportation and accommodation options for out-of-town visitors. In addition, its geographic footprint would have been about 40% smaller than NERC’s existing office, aligning with management’s desire to provide employees more flexible remote work options after the COVID-19 pandemic showed that staff could still execute their responsibilities while working from home.

Sharp acknowledged in Wednesday’s meeting that the collapse of negotiations means that the new lease and its promised benefits will not happen. However, he said that unspecified “incentives” that the organization negotiated with its current landlord will “help reduce our facility costs over the last several years of the lease.”

Those lower costs are not reflected in NERC’s 2022 Business Plan and Budget, which FERC approved on Tuesday. (See related story, FERC Approves ERO 2022 Budgets.) That document is based on the existing rent schedule for the Atlanta office. Sharp said any differences will be reconciled through NERC’s quarterly variance reports to the commission.

“We’ll take advantage of this time over the next couple of years to learn from the implementation of the new flexible workforce model and our collaborate-focused space in the Washington, D.C. office,” Sharp said. “And then we’ll evaluate what improvements would make sense in Atlanta and continue to design the best possible experience for our employees and stakeholders, with a focus on cost-effectiveness.”