FERC Remands GridLiance ATRR Settlement

FERC last week rejected a contested settlement agreement between SPP and GridLiance High Plains and remanded the proceedings back to the chief administrative law judge to resume hearing procedures (ER18-99).

In an order approved at its open meeting Thursday, the commission said SPP’s 2019 settlement offer was contested and could not be approved under any of the four Trailblazer approaches for approving contested settlements.

The docket was opened in 2017 when SPP proposed tariff revisions to add an annual transmission revenue requirement (ATRR), a formula rate template and implementation protocols for GridLiance-owned facilities in Nixa, Mo. The RTO decided to place the facilities in transmission pricing Zone 10 because they served load located there.

GridLiance ATRR Settlement — Nixa’s (Mo.) transmission facilities are at the center of a dispute between GridLiance and other SPP members. | *City of Nixa*

Several parties protested, including several cities in the zone, Nebraska Public Power District and a group of SPP transmission owners. FERC set the Tariff revisions for hearing and settlement judge procedures in March 2018.

GridLiance eventually reached an agreement with the Missouri cities that was certified by an ALJ last year. At the same time, the judge determined several issues were “arguably policy concerns that do not constitute genuine issues of material fact” and that the record contained substantial evidence upon which FERC could reach a decision in accordance with Trailblazer.

The TOs said the real issue was the originally proposed cost allocation, which would not be improved by the settlement. The commission agreed, saying the alleged cost shift caused by the Nixa assets’ inclusion in the zone was not addressed by the settlement.

FERC said its review of the record “shows that there may be a significant rate increase for Zone 10 customers upon the inclusion of the Nixa assets.”

“Based on the issues raised by the [TOs] with respect to the cost shift caused by the inclusion of the Nixa assets into SPP that we are unable to resolve based upon the record before us, we cannot approve the settlement under the first Trailblazer approach,” the commission said.

FERC did not address the merit of the TOs’ other issues because it rejected the first Trailblazer approach based on the cost shift issue.

Under the Trailblazer precedent, FERC may approve a contested settlement:

“if [it] can address the contentions of the contesting parties on the merits.” The commission has held that it “cannot approve a contested settlement under this approach if some of the contesting parties’ positions are found to have merit or the record lacks sufficient evidence to support a finding on the merits.”
“as a package on the grounds that the overall result of the settlement is just and reasonable.” The approach requires a “detailed and independent cost-benefit analysis … versus continued litigation.”
“where it determines that the contesting party’s interest is sufficiently attenuated that the settlement can be analyzed under the fair and reasonable standard applicable to uncontested settlements, and the commission [makes] an independent finding that the settlement benefits the directly affected settling parties.”
“for consenting parties and sever the contesting party or any contested issue.”

Basin Electric Rate Order Sustained

FERC last week also sustained a September 2020 order that accepted Basin Electric Power Cooperative’s 2020 rate schedule and wholesale power contracts but that also opened an investigation under Federal Power Act Section 206 into the rates’ justness and reasonableness. The order also granted clarification requests regarding the proceedings’ scope (ER20-2441).

In its September order, the commission found Basin’s rate schedule and power contracts with its 19 members raised factual issues that should be addressed through hearing and settlement judge procedures. It disagreed with intervenors’ arguments that a lack of withdrawal and termination procedures rendered the wholesale contracts unjust and unreasonable, saying each contract includes provisions requiring notice of termination for the contract term’s end. (See FERC to Investigate Basin Electric Rates; Danly Dissents.)

Wheat Belt Public Power District and McKenzie Electric Cooperative both filed clarification requests or, in the alternative, a rehearing of the September order. Dakota Energy Cooperative and Meeker Cooperative Light & Power Association filed a joint request for rehearing.

FERC denied the rehearing requests but granted Wheat Belt’s and McKenzie’s requests for clarification.

In other orders from last week’s meeting:

the commission conditionally accepted SPP’s compliance filing that lets interconnection customers know where in the RTO’s business practices manuals or other coordination documents they may find the modeling details staff use when studying a project as energy resource interconnection service or network resource interconnection service. SPP has 30 days to revise sections of its “Guidelines for the SPP GIP Process and Business Practices” document (ER20-945).
FERC approved an uncontested settlement agreement addressing the ratemaking treatment of Northwest Iowa Power Cooperative’s grandfathered agreements with MidAmerican Energy, saying it resolved all remaining issues set for the original hearing. The commission applied the Mobile-Sierra “public interest” presumption obligating it to treat any freely negotiated wholesale transaction as satisfying the requirement of justness and reasonableness unless it finds that the agreed-upon arrangements seriously harm the public interest (ER15-2115).

February 22, 2021

National Grid Explores Hydrogen for Home Heating

National Grid is participating in research to determine how to convert existing gas networks to support hydrogen that could be used for home heating, Kristin Munsch, the utility’s director for regulatory and consumer strategy, said Wednesday.

Hydrogen is a versatile source of energy that presents the opportunity to use existing infrastructure to meet climate goals, Munsch said during a virtual panel event hosted by the Northeast Energy and Commerce Association.

Space and water heating is the second largest source of emissions in Massachusetts, according to data from the Massachusetts Clean Energy Center, and most New England buildings are currently heated by fossil fuels.

Large wind projects, such as those in the U.K. and Europe, are producing an oversupply of energy that can be used for hydrogen production, independent energy market researcher Brad Bradshaw said during the panel discussion. The stranded electrons can be monetized by powering water electrolysis to produce hydrogen, which can then be put in pipelines for things like steel manufacturing or blending with natural gas.

“It seems to meet a lot of challenges” related to Massachusetts’ climate goals, Munsch said.

Because hydrogen is not a new industry, it already has an extensive supply chain, Bradshaw said. Handling the storage and transportation of hydrogen is “done in a well-experienced industry and a safe, economical manner.”

National Grid Hydrogen — National Grid is exploring supply chain options for hydrogen that could include using facilities like the one in this rendering to make hydrogen from excess wind power. | *Shutterstock*

Research is now focused on how to “pipe the hydrogen within homes safely and test [hydrogen] with different appliances,” he said.

“Several boilers are already manufactured around the world that take in 100% hydrogen to produce heat for homes, so it’s not really challenging,” Bradshaw said. “It’s just new.”

Excess solar and wind from grids in New York and Maine can be converted to hydrogen and transported cost effectively in high-capacity compressed tube trailers to places like Boston to help decarbonize the gas system, he said.

In the U.K., where the utility is headquartered, National Grid is researching different “flood rates” of hydrogen to a network of more than 100 residential buildings and commercial office spaces, Munsch said. The utility is learning from colleagues in the U.K. about what kind of pipes to use to transport hydrogen.

“The question now is how does it behave differently in our distribution systems,” Munsch said, as New England has “a lot of old pipes.”

National Grid has also partnered with the New York State Energy Research and Development Authority and Stony Brook University’s Institute for Gas Innovation and Technology to assess the impact of introducing hydrogen to infrastructure in New England.

In New York, National Grid has a proposal pending for a multiuse hydrogen production and utilization facility in collaboration with Standard Hydrogen Corp. The renewable natural gas produced will be injected into National Grid’s gas distribution system. The facility would also incorporate carbon capture, utilization and sequestration.

Research into hydrogen as a source of thermal energy is a “question of keeping all of our options open” for the anticipated increase in electrification of sectors such as heating and transportation, Munsch said.

February 22, 2021

PJM MRC/MC Preview: Feb. 24, 2021

Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members committees on Wednesday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

Consent Agenda (9:05-9:10)

B. The MRC will be asked to endorse proposed revisions to Manual 40: Training and Certification Requirements resulting from a periodic review. The Operating Committee endorsed the revisions Feb. 11. (See “Manual 40 Changes Endorsed,” PJM Operating Committee Briefs: Feb. 11, 2021.)

Endorsements/Approvals (9:10-11:00)

1. Black Start Unit Testing, CRF, Involuntary Termination, MTSL and Substitution (9:10-10)

A. Members will be asked to endorse a proposal addressing black start unit involuntary termination, substitution rules, capital recovery factor (CRF) and minimum tank suction level (MTSL). Greg Poulos, executive director of the Consumer Advocates of the PJM States, introduced the proposal on behalf of the Delaware Division of the Public Advocate at the January MRC meeting after proposals from PJM and Dominion Energy failed to receive endorsement. (See PJM MRC/MC Briefs: Jan. 27, 2021.)

B. Susan Bruce of the PJM Industrial Customer Coalition and Sharon Midgley of Exelon will also ask stakeholders to endorse an alternative PJM proposal on the same issue on first read. The proposal received 43% stakeholder support at the OC in December.

2. Storage as a Transmission Asset (SATA) (10-10:40)

The MRC will be asked to endorse PJM’s proposal for addressing how storage should be considered in the Regional Transmission Expansion Plan, along associated tariff and Operating Agreement revisions. Stakeholders endorsed the proposal at the Planning Committee in December. (See PJM PC OKs RTEP Rules for SATA.)

3. Competitive Exemption OA Revisions for SATA Resources (10:40-11)

Contingent on approval of the SATA proposal, Sharon Segner of LS Power will introduce a friendly amendment with OA revisions specifying, among other things, that SATA resources are ineligible for qualifying as immediate-need reliability projects.

Members Committee

Consent Agenda (1:20-1:25)

B. Stakeholders will be asked to endorse proposed Tariff Attachment K and OA Schedule 1 revisions addressing market rules for real-time values. The package was endorsed with a sector-weighted vote of 4.9 (98%) at the January MRC meeting. (See “Real-time Values Market Rules,” PJM MRC/MC Briefs: Jan. 27, 2021.)

C. The MC will be asked to endorse proposed tariff, OA and Reliability Assurance Agreement (RAA) revisions addressing the disposition of price-responsive demand credits. The package was unanimously endorsed at the January MRC meeting. (See “PRD Credits Disposition,” PJM MRC/MC Briefs: Jan. 27, 2021.)

D. Members will be asked to endorse proposed tariff and OA revisions related to stability limits in markets and operations. The package was endorsed with a sector-weighted vote of 4.05 (81%) at the January MRC meeting. (See “Stability Limits Endorsed,” PJM MRC/MC Briefs: Jan. 27, 2021.)

Endorsements/ Approvals (1:25-2:25)

1. MC Resolutions (1:25-2:25)

Midgley and Jim Davis of Dominion Energy will ask stakeholders to endorse a proposal, along with associated OA revisions, developing rules to address sufficient member approval of a resolution at the MC. Poulos will review an alternative proposal.

February 22, 2021

MISO Touts $3.5B in 2020 Savings for Members

MISO said its members collectively saved about $3.5 billion in 2020 for choosing RTO membership over going it alone on the grid.

The grid operator’s 2020 value proposition study showed that it provided between $3.1 billion and $3.9 billion in regional benefits. The annual value proposition study compares utility benefits of RTO membership versus flying solo.

MISO chalked the savings up to improved reliability, more efficient use of the region’s existing assets and reduced need for new assets.

Despite the pandemic, the cost reductions didn’t change much from a year earlier, when MISO said it saved members between $3.2 billion and $4 billion. For the past four years, the grid operator has claimed annual cost savings between $3 billion and $4 billion. (See MISO Estimates up to $4B in 2019 Benefits.)

Spokesperson Brandon Morris said the pandemic didn’t affect value proposition results because MISO was able to consistently maintain normal reliability and operations functions.

“Our member utilities’ shared commitment to serving the footprint reliably — combined with relatively stable year-over-year load levels as compared to 2019 — resulted in a 2020 value proposition which was largely shielded from the devastating impacts of COVID-19,” Morris told RTO Insider.

“The value proposition has been relatively stable for the past few years at about $3.5 billion,” Strategy and Business Development Adviser Brad Decker told stakeholders at a teleconference Feb. 19 to discuss the savings.

MISO 2020 Member Savings — MISO’s Carmel headquarters | © *RTO Insider*

MISO has documented more than $30 billion in benefits to its members since 2009. “This benefit has grown as MISO has grown,” Decker said.

Broken down, MISO estimated it has saved members between $384 million and $447 million because of its ability to offer improved reliability and perform compliance tasks on behalf of its members.

The RTO said members also avoided spending another $517 million to $572 million because it dispatches existing assets efficiently and offers energy regulation and spinning reserves.

“Before MISO, the region operated as a decentralized, bilateral market,” Decker said. “Now, the day-ahead and real-time market processes are used to minimize total production costs.”

But MISO said its most attractive benefit is its members’ diminished need to build new generating assets, worth between $2.47 million to $3.22 million in savings.

The grid operator said its footprint diversity accounted for about $1.9 billion to $2.4 billion of that reduced need for assets. Decker said the RTO’s geographic expanse means load can rely on other generation assets because weather and demand fluctuate by region.

“If you shared a car with your neighbors, you have fewer cars in garages, and that’s exactly what’s happening under footprint diversity,” Decker said.

Other drivers of the reduced generation need were MISO’s efforts to better incorporate wind into the resource mix, which it valued at a $450-$517 million savings to members, and its demand response programs, which it valued at $116-$211 million.

“MISO’s regional planning enables more economic placement of wind resources, reducing the overall capacity needed to meet required wind energy output,” Decker said.

February 22, 2021November 2, 2023

Consumer Advocates Question Nevada Solar Program

A plan to build small community solar projects and reduce electric bills for some low-income residents in Nevada is facing pushback from consumer advocates, who object to passing program costs to nonparticipating ratepayers.

The proposed Expanded Solar Access Program is the result of Assembly Bill 465, passed by the Nevada legislature in 2019. The Public Utilities Commission of Nevada has been conducting a rulemaking since mid-2019 to spell out details of the program, which would be run by the state’s monopoly electric provider, NV Energy.

AB465 specifies that the cost of the discount for low-income customers must be spread across all of the utility’s ratepayers.

But the bill does not contain a similar provision for other costs of the program, according to the Bureau of Consumer Protection (BCP), which is part of the Nevada Attorney General’s Office. Yet PUCN’s proposed regulation states that “all costs related to the Expanded Solar Access Program are public policy costs that must be charged to all customer classes of an electric utility.”

“The only subsidy allowed under Assembly Bill 465 to be charged to nonparticipating customers is that of the low-income discount,” Senior Deputy Attorney General Michael Saunders said in a Feb. 16 letter to PUCN. “The Expanded Solar Access Program was intended to be a stand-alone program with its costs covered by participating customers.”

The letter reiterated concerns that BCP expressed in written comments last year. And PUCN’s regulatory operations staff, which is separate from the agency’s decision-making side, have also expressed concerns about spreading program costs other than the low-income discount to all ratepayers.

“This outcome does not seem just and reasonable since remaining ratepayers will receive no direct benefit from this program,” Assistant Staff Counsel Shelly Cassity said in a May 29 letter to the commission.

NV Energy did not respond to requests for comment on the Expanded Solar Access Program. A spokesperson for the attorney general’s office said BCP could not comment on issues related to rulemaking.

PUCN held a workshop and a hearing last week on its draft regulation for the program. The commission now plans to release a revised draft, to be followed by another written comment period and hearing.

As outlined in AB465, which was sponsored by Assemblywoman Daniele Monroe-Moreno (D) of North Las Vegas, the Expanded Solar Access Program would include three to 10 community-based solar projects in areas with a concentration of low-income residents. NV Energy would own and operate the solar facilities, which would be connected to the company’s distribution system.

NV Energy would also include at least one utility-scale solar resource in the program. The utility-scale facility is necessary to make the program affordable to residents, NV Energy officials said during hearings on the bill.

Program participants would fall into three categories:

nonprofits and disadvantaged businesses, including those owned by minorities or low-income residents,
residents whose income falls below 80% of the area median, and
residential customers who show that they cannot install their own solar projects because of rental agreements or site constraints.

The program would establish its own electric rates. Low-income residents in the program would be guaranteed a reduced rate. Other participants would have “stability and predictability” in their electric rates, although reduced rates are not guaranteed.

In another provision, the Nevada Department of Employment, Training and Rehabilitation would work with employers and the International Brotherhood of Electrical Workers to create solar job opportunities and a training program.

Break from Tradition

Monroe-Moreno has noted that AB465 is not a traditional community solar program.

In general, community solar programs allow participants to buy or lease part of an off-site solar photovoltaic system. The programs are also known as shared solar or solar gardens. As of June, community solar projects were found in 39 states and Washington, D.C., according to the National Renewable Energy Laboratory within the U.S. Department of Energy.

Nevada came close to enacting a community solar bill during the 2017 legislative session.

Senate Bill 392, by Sen. Mo Denis (D) of Las Vegas, would have allowed community solar gardens run by subscriber organizations, with individual subscribers receiving a credit on their electric bill for their share of electricity generated by the solar garden.

The legislature passed SB392, but then-Gov. Brian Sandoval vetoed it, saying he was concerned that community solar gardens would operate as small utilities, only without the same level of regulation.

Sandoval was also concerned about the bill’s timing. Nevada residents were preparing to vote in November 2018 on the Energy Choice Initiative, which would have moved the state from an electric monopoly to a competitive market. The initiative failed.

AB465 garnered support from organizations including the Sierra Club Toiyabe Chapter, Western Resource Advocates, IBEW and the Nevada State AFL-CIO. Supporters pointed to the bill’s environmental and workforce benefits.

Nevada Conservation League representative Kyle Davis said during a Senate committee hearing that although the bill wouldn’t create a traditional community solar program, it would be “a step forward, especially for low-income ratepayers.”

But some groups opposed AB465.

The Solar Energies Industry Association, a national trade group, objected to the fact that the bill would allow solar projects approved as long ago as 2018 to be included in the program. SEIA said it would prefer that the program add new solar projects.

The Coalition for Community Solar Access shared SEIA’s concern. The group also said it wasn’t clear how much program participants would save on their electric bills.

Those issues and others “make this bill … an unnecessary and deeply flawed experiment for the state, especially with tried-and-true best practices to be leveraged from over a dozen other states,” CCSA Executive Director Jeff Cramer said in a May 2019 letter to the Senate Committee on Growth and Infrastructure.

February 22, 2021

FirstEnergy Shares Jump on Icahn Investment

FirstEnergy officials updated investors Thursday on the ongoing investigation into the fallout from House Bill 6 during its fourth quarter earnings call while also disclosing billionaire investor Carl Icahn is looking to acquire a stake in the company.

Officials said it disclosed in its most recent filing with the Securities and Exchange Commission that it received a letter Feb. 16 from Florida-based Icahn Capital informing them that Icahn is making a filing with the Federal Trade Commission of its intention to acquire voting securities of FirstEnergy in “an amount exceeding $184 million but less than $920 million,” depending on market conditions. The company’s market capitalization is almost 18.5 billion.

FirstEnergy said it does not know whether Icahn or his associates have already acquired FirstEnergy stock, and it did not know his intentions regarding the company. The letter was the only contact so far with Icahn, officials said.

Icahn earned a reputation in the 1980s as a “corporate raider,” known for his hostile takeover and asset stripping of airline TWA. Icahn briefly served as an economic adviser in the Trump administration in 2017.

FirstEnergy’s share price jumped 7.2% to $34.25 by the end of trading on Thursday on the news involving Icahn, climbing as high as $35.36 per share after noon. Nearly 19 million shares traded hands, about three times as many on a typical day in the last year. The share price closed Friday at $34.03 on a trading volume of 5.3 million shares.

FirstEnergy Investment — FirstEnergy President Steven Strah | *FirstEnergy*

“We thought it was noteworthy, and that’s why we’re just being open and transparent about it,” acting CEO and FirstEnergy President Steven Strah said. “We just don’t know enough at this point.”

An electric utilities industry analyst at KeyBanc in Cleveland said in a note to clients that Icahn was likely attracted because FirstEnergy is undervalued.

“We believe that there are multiple avenues for [FirstEnergy] to close its valuation gap where an activist could have an impact – up to and including a sale of the company,” said KeyBanc analyst Sophie Karp, who added that Icahn’s interest could result in a sale of the utility or of non-core assets.

HB 6 Investigation

Thursday’s earnings call was the first held since five FirstEnergy officials were fired in the wake of the fallout surrounding the alleged $61 million bribery scheme that resulted in the passage of HB 6 to rescue struggling nuclear plants in Ohio at a cost to the public of more than $1 billion. The scandal also claimed Ohio Public Utilities Commission Chair Sam Randazzo, who resigned after the FBI raided his home. Randazzo has not been charged in the Justice Department investigation of the scheme. (See PUCO Chair Randazzo Resigns.)

Neither FirstEnergy nor its former executives have been charged.

But on Friday, the Justice Department’s Southern District of Ohio announced that Generation Now, a nonprofit social welfare agency at the center of the purported racketeering scheme created to conceal more than $60 million in corporate money to former Ohio House Speaker Larry Householder, pleaded guilty to one count of racketeering conspiracy.

Householder and his longtime political strategist Jeffrey Longstreth signed the guilty plea on behalf of Generation Now. Longstreth pleaded guilty in October to an identical individual charge and faces up to 20 years in prison. Householder has pleaded not guilty and is awaiting trial. Stripped of his title as speaker, Householder continues to serve as a state representative. Strah, who took over for former CEO Charles Jones after he was fired in late October, said FirstEnergy is “deeply committed” to creating a culture in the company where its leaders “encourage open and transparent communications with all of our stakeholders.” (See FirstEnergy Fires Jones over Bribe Probe.)

“We are dedicated to re-emphasizing that every employee at every level has the responsibility to consistently act in accordance with our core values and behaviors and to speak up if they see inappropriate behavior anywhere in the organization,” Strah said. “At the same time, we’re taking decisive actions to rebuild our reputation and brand and focus on the future.”

Strah said FirstEnergy is continuing to cooperate with the Department of Justice and SEC as the investigation into the alleged bribery scheme continues.

Christopher Pappas, FirstEnergy executive director and independent board member, said the company’s internal investigation has not resulted in any new material to disclose. Pappas said investigators have found certain transactions, including vendor services, that were either improperly classified, misallocated to utility or transmission companies or lacked proper supporting documentation.

The transactions, Pappas said, resulted in amounts collected from customers that were “immaterial” to FirstEnergy and will work with regulatory agencies “to address these amounts.” The exact amounts were not disclosed.

“Our internal investigation continues to be thorough and robust and includes assistance from external law firms who are supported by several other consultants,” Pappas said.

FirstEnergy announced it has stopped making political contributions and will no longer make contributions to political nonprofit 501 (c) (4) organizations.

The company on Thursday also named John Somerhalder, a former executive with CenterPoint Energy in Texas, as vice chairman of FirstEnergy. Somerhalder will also serve as executive director and a member of FirstEnergy’s executive leadership team in a transitional capacity and is tasked with improving the company’s governance and rebuilding relationships with regulators.

Clean Energy Investment

FirstEnergy reaffirmed its commitment to modernizing its grid and becoming carbon neutral by 2050. Last year, the company invested $3 billion in its distribution and transmission system and grid modernization. FirstEnergy continues to operate about 3,100 MW of coal-fired power plants in West Virginia, according to its most recent 10K filing. The company has committed to owning 50 MW of solar generation in West Virginia by 2030 and has pledged to look for other ways to reduce coal burning in the state. “We believe robust long-term organic growth opportunities are well aligned with the focus on electrification and the critical role the grid plays in supporting the transition to a carbon neutral economy,” Strah said.

The company recently announced a $19.6 million project to construct a new transmission substation in Trumbull County, Ohio, to support the energy demands of the electric vehicle industry expanding in the region. The new transmission infrastructure will provide electric service to Ultium Cells — a 3 million-square-foot EV battery-cell manufacturing plant backed by General Motors and South Korea’s LG Chem.

In its strategic plan announced last month, FirstEnergy pledged to achieve carbon neutrality by 2050. It said all new light-duty and aerial trucks will be electric or hybrid vehicles beginning this year and 30% of the fleet will be electrified by 2030.

“This ambitious goal reflects our transformation to a regulated electric utility and our responsibility to help create a sustainable energy future,” Strah said.

Earnings

The company reported earnings of $1.1 billion ($1.99/share), on revenue of $10.8 billion for fiscal year 2020 and $242 million ($0.45/share) on revenue of $2.5 billion for its fourth quarter.

The year-end results were an improvement over 2019, when the company earned $908 million ($1.70/share) on revenue of $11 billion.

FirstEnergy CFO Jon Taylor said he expects a profit of $1.3 billion to $1.4 billion for the current 2021 fiscal year.

FERC Docket Closed

Also Friday, Energy Harbor Settles with Solar Co. for $66M.)

John Funk contributed to this report.

February 22, 2021

Con Edison 2020 Earnings down 18% YOY

Consolidated Edison on Thursday reported net income of $1.1 billion ($3.29/share) for 2020, down about 18% from the previous year because of lower commercial and industrial demand during the COVID-19 pandemic and costs associated with Tropical Storm Isaias last August.

The company’s net income for the fourth quarter was $43 million ($0.13/share), compared with $295 million ($0.89/share) for the same period in 2019.

“I want to thank our essential frontline employees for their dedication and sacrifice throughout the pandemic. Their exceptional work in providing safe and reliable energy to New Yorkers has made a critical difference throughout this most difficult year,” CEO Timothy P. Cawley said in a statement.

Con Edison 2020 earnings — Con Edison deployed a 1-MW generator to support the field hospital at the Brooklyn Cruise Terminal in Red Hook. | *Con Ed*

Last March, Con Ed began suspending utility service disconnections, certain collection notices, final bill collection agency activity, new late payment charges and certain other fees for all customers. The company estimates foregone revenues at approximately $61 million and $3 million for Consolidated Edison Company of New York (CECONY) — its utility subsidiary serving New York City and Westchester County — and Orange and Rockland Utilities (O&R), respectively.

The company estimates the financial impact from COVID-19 for the full year to be $102 million. CECONY’s C&I demand was down 15% for the year, with revenue for the sector down 13%; O&R’s were down 9% and 8%, respectively.

The New York Public Service Commission in January approved further investigation into the Isaias preparation and response by Central Hudson Gas & Electric, CECONY, O&R and PSEG Long Island. PSEG is not under PSC jurisdiction, but the other three utilities “now face maximum potential penalties of up to $137.3 million, with Con Edison and O&R also facing potential license revocation depending upon a finding of repeat violations,” the commission said. (See “NYSEG Dinged for Isaias; Other IOU Cases Pending,” NY PSC OKs Utility Storage Deployment, Cost Recovery.)

New York Gov. Andrew Cuomo on Friday announced that he is advancing legislation to eliminate caps on penalties to ensure they align with actual damages caused by specific violations and to establish a clear process for revocation of a utility’s operating certificate upon recurring failures.

February 22, 2021

NY Needs ZEV Job Training, Strategy, Officials Say

New York’s push to electrify its transportation system will require a “massive” job training effort and public policies sharply focused on putting more electric vehicles on the road, experts said last week.

Rather than adopting a business-as-usual approach to the phase-in of EVs, the state should accelerate the goals expressed in the Climate Leadership and Community Protection Act (CLCPA), said Jared Snyder, deputy commissioner of New York’s Department of Environmental Conservation.

New York ZEV — NYSERDA EV chargers: An employee’s vehicle charging at a GE facility in Schenectady, New York | *NYSERDA*

The CLCPA mandates that the state consume 70% renewable electricity by 2030, 100% carbon-free electricity by 2040, and reduce emissions 85% by midcentury from 1990 levels.

“We’re going to be talking about policies that accelerate the transition so that by 2035 we’re seeing 100% electric vehicle sales, with a goal that by 2050 practically all cars are going to be electrified,” Snyder said Thursday at a meeting of the New York Climate Action Council’s transportation advisory panel, which met to discuss zero-emission vehicle (ZEV) job training requirements and adoption strategies that it might recommend to the Council.

A similar transition will be necessary for trucking, he said, “so we need to think about how do we accelerate that workforce transition at the same time,” he said.

Electrification of the transportation sector is helping attract young talent into the industry in New York, according to Porie Saikia-Eapen, director of environmental sustainability and compliance for the Metropolitan Transportation Authority, the agency managing public transportation in the New York City area.

“We are getting a lot of young people interested in coming to work for public transit — environmental scientists coming straight out of college,” Saikia-Eapen said.

Back to Basics

The coming wave of EVs will require “a massive training component” for both technicians and drivers, said Kendra Hems, president of the Trucking Association of New York.

New York aims to have 850,000 EVs on the road by 2025, up from about 100,000 now, and two million by 2030. The New York State Energy Research and Development Authority (NYSERDA) runs ChargeNY, a program to support the adoption of EVs with incentives such as rebates, as well as utility and geographic data on vehicle sales and the installation of charging stations.

The state’s Public Service Commission last July approved over $700 million to install more than 50,000 light-duty EV charging stations throughout the state through 2025. (See NYPSC Approves $700 Million for EV Chargers.)

Internal combustion engine technology has changed so dramatically over the years that the number of computers onboard a vehicle to measure timing and atmospheric conditions and adjust the engine all became a real training issue for technicians, said Steve Finch, senior vice president of the American Automobile Association in western and central New York.

“All those were ‘additive’ technologies, whereas what we’re talking about now with electrification is a total disruption to that industry,” Finch said. He recounted that AAA recently got a call for a Tesla vehicle that had run out of charge on the side of the road, but the tow truck driver didn’t know how to hook up the vehicle to move it.

“We’re not talking about repairs to the engine — he didn’t know how to pick up the vehicle and put it on the flatbed truck to move it,” Finch said.

Kerene Tayloe, director of federal legislative affairs at WE ACT for Environmental Justice, said the evolution to ZEVs will happen in cycles, so the workforce training strategy for a midcareer worker should be different from how schools prepare a 10-year-old student for transportation-related work.

Paul Allen, M. J. Bradley & Associates | *NYDPS*

“We have to reach children now, because they are going to be the workforce of the future,” said Paul Allen, senior vice president with M. J. Bradley & Associates consultancy.

Allen also wrote in the chat area of the webinar that the power industry has an ongoing program with the U.S. military services to bring qualified, highly skilled workers into complex technical jobs — helmets to hardhats — which could be a good source of well-trained midcareer workers for green transportation.

Forward Strategies

Adam Ruder, NYSERDA project manager for transportation R&D and market development, presented on two strategies to encourage development of the EV market: one for transitioning to 100% zero-emission light-duty vehicles and the other for switching to medium- and heavy-duty EVs. (See related story, NY Considers Rulemaking for Medium to Heavy ZEVs.)

“These are two of the strategies we think will have a great impact on overall transportation emissions, but these alone are not going to achieve our 2030 and 2050 goals,” Ruder said. “We will need contributions from the other policies under consideration, as well as the ones focused on system efficiency and other alternative tools.”

The role of utilities elicited differing opinions on the proper parameters for utility engagement.

New York’s six local distribution companies split over whether to adopt “passive” or “active” approaches to managing EV charging in proposals submitted to the PSC in December. (See NY Utilities Diverge on Managed EV Charging.)

As a general rule, Allen said, increased electric revenues actually depress electric rates for all ratepayers, so the net-net economic impact of moving to electricity as a fuel for transportation is going to tend to lower electric rates across the state for all ratepayers, “especially given the way the PSC is likely to look at the issue.”

Some of the debate about the role of utilities is policy-related, said Elgie Holstein, senior director for strategic planning at the Environmental Defense Fund.

“We’ve been approached by national organizations representing service stations, dealers, and also that rather large group that represents convenience store operators, and they don’t want electric utilities involved in this business at all,” Holstein said. “They don’t want electric utilities investing in charging stations, and they want federal prohibitions that prevent it. I don’t know where that’s headed, and I don’t think we’re going to support that, but they’re trotting out all kinds of claims that costs to consumers and ratepayers will go up if electric utilities are allowed into this space.”

The role of the utilities is not necessarily owning charging stations, but in New York, that role is already being defined through the make-ready order that was passed in May 2020 by the PSC, Ruder said. (See NYPSC Launches Grid Study, Extends Solar Funding.)

He said the upgrades are necessary for reliability purposes “and for ensuring that there is a managed charging capability.”

“If someone wants to use electricity, the utilities in this country have an obligation to serve them. I’m aware of what these national organizations are saying, and I just think they have their facts wrong in many instances,” he said.

February 22, 2021March 9, 2025

Glick Eyes New Standards Following Texas Outages

Map of ongoing outages in Texas. As of 3:17 p.m. Feb. 18, more than 375,000 outages were still reported statewide. | PowerOutage.US

FERC Chairman Richard Glick said Thursday he may seek new reliability standards to ensure generators and grid operators are prepared for severe winter conditions following this week’s devastating outages in Texas and neighboring states.

While praising the efforts of those working to restore power to the affected areas — particularly Texas, where more than 350,000 outages were still reported across the state as of Thursday afternoon — Glick emphasized that losing electricity for days in the middle of a record cold snap was “simply unacceptable” and “constitutes a humanitarian crisis.” (See related story, ERCOT: Grid was ‘Seconds and Minutes’ from Total Collapse.)

Many customers were without power for days, and more than 35 deaths have been attributed to severe weather in Texas and other states. FERC and NERC announced on Tuesday that they will conduct a joint inquiry into the causes of the crisis. (See Anger Rises over Midwest Power Restoration.)

On Monday, FERC announced that the Office of Enforcement’s Division of Analytics and Surveillance will be combing through wholesale natural gas and electricity market data to determine if any market participants engaged in market manipulation or other violations. The Division uses trading data to screen transactions at most physical and financial natural gas trading hubs in the U.S. and the organized and bilateral wholesale electricity markets. Evidence of wrongdoing would become the subject of non-public investigations.

Separately, FERC announced that it will open a new proceeding to examine the threat that climate change and extreme weather events — including droughts, extreme cold, wildfires, hurricanes, and prolonged heat waves — pose to electric reliability and how grid operators prepare for them. The proceeding will include an opportunity for parties to submit comments, followed by a technical conference.

Glick Open to Changing ERCOT Status

Although ERCOT’s markets are not under federal jurisdiction, Glick noted that Texas is subject to NERC’s reliability standards, which are approved by FERC. He promised that the organizations’ inquiry would recommend steps necessary to prevent similar events in the future, possibly including “the imposition of new mandatory standards” for cold weather preparedness.

“[We] need to ensure that the results of the inquiry don’t just sit on the shelf gathering dust, like so many other reports of this kind, and that we don’t do what happened after the 2011 event in Texas and Arizona — rely on voluntary guidance to protect the public. We don’t have to guess how effective that was,” Glick said. “Instead, I’m prepared, if necessary, to support the imposition of new mandatory standards to make sure that electric generators and others are better prepared when weather strikes next time. And there will be a next time.”

Glick also said Congress and Texas should reconsider what he called the “go-it-alone approach” — ERCOT’s limited connection to the Eastern and Western Interconnections, which has allowed it to avoid being covered by the federal government’s jurisdiction over interstate transmission. “Does it really make sense to isolate yourself and limit your ability to get power from neighboring regions just to keep FERC at bay?” he asked.

He added that with climate change “already having a dramatic impact on our weather,” there is a clear need for quick action to reform readiness standards for the grid.

While commending Glick for his response to the emergency, Commissioner Neil Chatterjee argued that until the FERC-NERC inquiry is complete it is “too soon to try to advocate for solutions” including new mandatory standards. Chatterjee also distanced himself from Glick’s suggestion that Texas consider strengthening its ties to the other interconnections, urging participants to “let the experts dig into it.”

A snow-covered sidewalk in Deep Ellum, Texas. | Matthew T Rader, CC BY-SA 4.0, via Wikimedia Commons

Commissioner James Danly urged deliberation as well, observing that it has been “extraordinarily difficult to get even the basics” for comparing the performance of different types of generation during the cold spell.

“It is my fervent hope that my colleagues will show the solicitude to Texas that they often seem willing to afford all of the other states in pursuing their policy goals,” Danly said. “I see no reason to change ERCOT’s status unless Texas itself wants to.”

Anger at Premature Blame

Commissioners joined Glick in expressing frustration about what he called “interest group flacks trying to pin blame on one generation source or another.” Some figures in media and politics have speculated that renewable energy resources such as solar panels and windmills bear most of the blame for the widespread outages, although ERCOT data shows greater loss from thermal resources than from renewable ones. ERCOT said renewable performance “has been around the levels planned for.”

“Propagating such misinformation is irresponsible, and it’s callous, in light of the serious emergency situation we’re facing,” said Commissioner Allison Clements. “And presenting the cause of the outages should be done in a thorough, deliberate fashion, after we get the official data released. … For now we should continue to focus on the restoration of power.”

Chatterjee Questions Closing Resilience Docket

Also Thursday, the commission voted 4-1 to close the resilience docket it opened in January 2018, after rejecting then-Energy Secretary Rick Perry’s call for cost-of-service payments to coal and nuclear generators (AD18-7). (See FERC Rejects DOE Rule, Opens RTO ‘Resilience’ Inquiry.)

Some commissioners acknowledged the apparent inconsistency of closing the docket considering the ongoing energy crisis in Texas and the Midwest.

The docket sought feedback on how to define resilience and how each of the RTOs and ISOs assess resilience in their footprints. (See RTO Resilience Filings Seek Time, More Gas Coordination.) But the majority said it concluded that a “generic” response to resilience concerns in all regions was inappropriate and might violate the Federal Power Act.

“That is not to suggest that resilience concerns are no longer an issue or that RTOs and ISOs have addressed all threats to the resilience of the bulk power system,” they said. “To the contrary, the resilience and reliability of the bulk power system must — and will — remain one of the commission’s paramount responsibilities and concerns.”

Instead, they said the issues should be addressed “on a case-by-case and region-by-region basis. Be it wildfires in the West, hurricanes in the Southeast, or even the extreme cold weather experienced this week in Texas and the Great Plains, these threats present stark, but different challenges to the reliability of the electric grid. Addressing those individual challenges in a manner that is both effective — for the grid and the region — and consistent with our statutory authority under the FPA requires an approach that is tailored to the specific threats and circumstances in a particular region, not a one-size-fits-all solution.”

Commissioner Chatterjee dissented, saying he was “not satisfied with a piecemeal, passive approach to ensuring its resilience, especially in the face of anticipated load increases due to economy-wide electrification goals.”

“The commission is well positioned to, for instance, adopt a definition of resilience that could be implemented in all regions, describe categories of resilience concerns that would include extreme weather events and common-mode failures, and then take additional steps to ensure that the commission, RTOs/ISOs, and stakeholders can understand how each RTO/ISO assesses the resilience of its region,” he said. “Such a holistic review would not only assist RTOs/ISOs and their stakeholders in considering different approaches to these efforts, but also help the commission understand how to best assess and address bulk power system resilience.”

Commissioner Danly filled a concurrence, but said he was concerned “that the resilience issues raised in this proceeding have not been solved — indeed, in most cases they have not even been addressed.”

He said the blackouts this week in ERCOT, SPP and MISO — following those last summer in CAISO — indicated an “urgent need for reform” to address market failures that are leaving dispatchable generation without enough revenue to invest in necessary upgrades.

“Many regions lack meaningful capacity markets, and the regions that do have capacity markets often allow state-subsidized resources to suppress prices such that the capacity markets cannot achieve one of the goals they were designed to achieve, which is to provide for revenues adequate to create incentives for the construction and operation of sufficient generation capacity to ensure reliability,” Danly said.

He also said RTO rules have been insufficient to persuade most gas-fired generators to obtain firm fuel contracts. “Increasing penalties when generators fail to obtain natural gas is a poor substitute for a market structure that compensates them for ensuring adequate fuel supplies in the first place,” he said. “Another increasingly serious problem is that intermittent resources largely are planned for, operated and compensated as if they provide reliability benefits that they, in fact, are incapable of providing.

“We have tended to focus too much on low, short-term prices and development of new, clean power sources to the detriment of reliability,” he continued. “I do not believe these latest power crises to be yet another perfect storm, but a case of reaping what we have sown.”

Commissioner Mark Christie joined with Clements on a separate concurrence, saying RTOS and ISOs “must be willing to face and speak inconvenient truths about what is — and is not — feasible from an engineering standpoint, given the state of technology. They must also tell the public and the elected political leaders at both the state and federal levels about the realistic impacts on the bills consumers will have to pay for reliability. Politically driven mandates and deadlines may not be grounded in engineering reality, and we depend on the leadership of each RTO and ISO to provide forthright information about what is needed to ensure the 24/7 power supply Americans expect.”

Resilient Society’s Rehearing Request Addressed

Separately Thursday, the commission sustained its 2018 ruling rejecting Perry’s request for a Notice of Proposed Rulemaking and addressed issues raised by Foundation for Resilient Societies in a rehearing request (RM18-1-001). The rehearing request had been automatically denied when the commission failed to act on it within 30 days.

“Resilient Societies raises various arguments that the commission should have considered specific issues or should have initiated additional proceedings, but none of its arguments persuade us that the January 2018 order was in error on the threshold question of whether the proposed rule and the record in Docket No. RM18-1-000 satisfied [FPA] Section 206,” the commission said. “For example, while Resilient Societies raises concerns about ‘ghost capacity’ in ISO-NE, those concerns do not demonstrate that ISO-NE’s existing tariff or the tariffs of other RTOs/ISOs are unjust and unreasonable.”

February 21, 2021

Southern Calif. Could Fail RA Test, WECC Says

The Western Interconnection’s California-Mexico (CAMX) subregion cannot maintain resource adequacy without imports, and the greatest risk of failing to meet load is in Southern California, WECC said last week.

Southern California RA — WECC’s CAMX subregion contains most of California and extends into Mexico. | *WECC*

“In 2021 and beyond, even with all planned resource additions, the CAMX subregion needs external assistance to maintain resource adequacy,” WECC said in a recent report and an online presentation last week. The summer-peaking CAMX subregion includes most of California and parts of Nevada and Baja California, Mexico.

Although imports “greatly reduce the probability of being resource inadequate, growing supply and demand variability across the interconnection increases the risk that imports may not be available when needed,” WECC said.

WECC said Southern California could experience two hours of unserved load this year and eight hours in 2022 under a one-day-in-ten-year (ODITY) threshold in a scenario that includes imports and resources currently under construction (Tier 1), or that have begun licensing, siting or permitting processes (Tier 2).

When analysts excluded Tier 2 resources, the number of hours Southern California would fail to meet the ODITY threshold increased to 10 in 2021 and 29 in 2024, WECC said.

If imports are excluded and only Tier 1 resources are available, the number of hours with potential demand at risk increases to 140 this year.

Unseasonal heat waves and Southern California’s dependence on capacity imported from other states make it especially vulnerable to blackouts like those it experienced last summer, the report said. Southern California Edison, which serves 15 million residents, has the largest percentage of demand and the widest variability in resource availability in the CAMX subregion, it said.

“The biggest problem … we’re facing is variability, and I think everyone’s aware of that,” Matt Elkins, WECC’s manager of performance and resource adequacy, said in the Feb. 16 webinar. “You really have to start looking at ‘What could the potential be?’”

Extreme heat waves in the West and frigid weather in Texas show traditional “expectations are off, and those are the kind of things we have to start planning for, especially with variable resources” such as wind and solar, Elkins said.

Northern California, mostly served by Pacific Gas and Electric, has a lower risk of resource inadequacy in the coming years and should be able to meet the ODITY threshold with imports and the addition of resources under construction or in the later planning stages, the report said.

In addition, changing weather and variable generation from renewable resources could mean a 15% reserve margin across all months is no longer adequate for CAMX, it said.

“In May and June, the months when variability in energy supply and demand is highest, a planning reserve margin near 40% may be needed,” to meet the 1-in-10 standard, the report said. “In fact, if a flat 15% planning reserve margin were applied to all hours of 2021, over 40% of the hours would not meet the [1 in 10] threshold.”

CAMX is expected to peak this year in late August at about 51,300 MW, with a 5% probability that the peak could hit 63,000 MW, a 25% load forecast uncertainty. The expected availability of resources on the peak hour is 57,800 MW, with a 5% chance of having only 44,400 MW available.

WECC’s latest subregional analysis followed its recent report on the Desert Southwest, which concluded that region is also at risk of failing to meet peak loads in 2021 and 2022 even under a best-case scenario. (See SW Faces RA Shortfall in 2021 and Beyond, WECC Says.)

The next and final subregional report on the vast Northwest Power Pool is expected Feb. 26 with a webinar scheduled on March 2.

The subregional reports build on WECC’s Western Assessment for Resource Adequacy, released in December, which found that the Western Interconnection could experience one to eight hours in which some of its subregions fail to meet load under the ODITY threshold. It recommended that Western utilities and state regulators increase coordination and adopt dynamic planning reserve margins to ensure the grid has adequate resources as it takes on more variable generation. (See Western RA Planning Must Change, WECC Says.)

Potential resource shortfalls have become a growing concern in California and other parts of the West as fossil fuel plants retire and renewable resources multiply. The issue took on new urgency in August and September 2020, when widespread heat waves prompted rolling blackouts in California and grid emergencies in neighboring regions.

Shortages occurred in the early evening as solar waned, not during the peak demand hour in the afternoon.

“That hour’s no longer the riskiest hour,” Elkins said. “It’s still the highest demand hour, but we’ve got to account for variability in other hours.”