Consolidated Edison said Thursday that the COVID-19 pandemic had negatively impacted its first-half earnings by $52 million — a report that came as the utility struggled to restore power to its more than 500,000 customers in and around New York City after Tropical Storm Isaias hit two days earlier.
The negative impact primarily reflects foregone revenues from the suspension of customer late payment charges and certain other fees associated with the pandemic, as well as higher depreciation and amortization expense, offset in part by the Employee Retention Tax Credit under the CARES Act, the company said.
Despite the effects of the pandemic, net income for the first six months of 2020 was $565 million ($1.69/share), only a 2% drop from the $576 million ($1.77/share) in the first half of last year. Con Ed also reported second-quarter net income of $190 million ($0.57/share), compared to $152 million ($0.46/share) during the same period in 2019.
Con Edison reported the pandemic had a negative impact on net revenues of $52 million in the first half of 2020. | Con Edison
“We are facing today’s unprecedented challenges by providing essential and reliable service during the pandemic,” CEO John McAvoy said in a statement. “We understand the hardship that Tropical Storm Isaias has had on our customers, and we are working around the clock to restore service.”
McAvoy said crews were restoring power to approximately 300,000 Consolidated Edison Company of New York (CECONY) and 225,000 Orange & Rockland Utilities (O&R) electric customers affected and called Isaias “the second-worst storm in our company’s history.”
Con Edison’s long-range plan forecasts EV-related usage will reach 7.2% of system peak, or 107 MW, in 2038. | Con Edison
The company highlighted the New York Public Service Commission’s decision in July to establish a light-duty electric vehicle “make-ready” program, which includes budgets of $290 million and $24 million for CECONY and O&R, respectively, through 2025, for fast-charger stations and other services. (See NYPSC Approves $700 Million for EV Chargers.)
NERC opened 45-day comment periods last week for proposed reliability guidelines on winter weather readiness and supply chain procurement, as well as on planned changes to its Critical Infrastructure Protection (CIP) standards.
Comments will be accepted on the reliability guidelines through 5 p.m. Sept. 21 and through 8 p.m. Sept. 21 for the CIP standards. In addition, ballots for the standards and implementation plan, along with nonbinding polls for associated violation risk factors and severity levels, will be conducted Sept. 11 to 21.
NERC Adds Detail to Winter Guideline
The proposed changes to the winter weather guideline were developed during the regular three-year review process for NERC reliability guidelines. The guideline is currently in its second version, approved in July 2017.
Updates in the most recent draft guideline include replacing references to the Operating, Planning and Critical Infrastructure Protection committees with the new Reliability and Security Technical Committee (RSTC), along with adding detail to the existing guideline’s recommendations for evaluating the readiness of critical components.
New to the recommendations is a clear deadline for finishing winter-related inspections, repairs and upgrades by the local first frost date as set by the National Oceanic and Atmospheric Administration. The guideline also adds lubricants, batteries, uninterruptible power supply systems, and heat tracing and ventilation systems to the list of components that utilities should check for winter readiness.
The winter reliability guideline is separate from the proposed cold weather standard currently under development by NERC (Project 2019-06). Some industry stakeholders have questioned the need for mandatory standards on the grounds that the existing guidelines should be sufficient, but NERC representatives have pointed to ongoing issues with cold weather as a reason for continuing the project. (See Cold Weather SDT Planning February Posting.)
“Out of the past 12 years, there have been six blackouts [from extreme cold] — that is a problem. … Obviously, the NERC guidelines may not be enough,” NERC Senior Standards Developer Jordan Mallory said at a meeting of the SAR drafting team in January.
Draft Supply Chain Guidelines Use Broad Strokes
NERC’s proposed supply chain procurement language guideline was developed under the Critical Infrastructure Protection Committee but moved to the RSTC following the merger of the technical committees. The guideline focuses on helping organizations implement effective controls in procurement agreements to prevent exposing themselves to cyberattacks through equipment purchases.
“Regulators have challenged the levels of rigor regarding risk management practices that organizations claim to have attained,” the guideline says. “Remedies applied through the inclusion of targeted controls in the procurement of cyber systems, components, maintenance and related services can assist in the development of a ‘risk-based’ approach to cybersecurity.”
Currently the guideline is in its first draft, so it lacks specific measures for entities to adopt. Instead, the document focuses on broader principles that utilities can follow in their contracts with suppliers, such as identifying cybersecurity risks that might be in play with a particular vendor and specifying audit mechanisms and metrics to ensure vendors are complying with needed changes.
The comment and balloting period for reliability standards CIP-004-7 and CIP-011-3 are hoped to be the last for Project 2019-02, which is focused on clarifying requirements to access bulk electric system cyber system information (BCSI) and establishing guidelines for encryption or other methods to protect such information.
Both standards saw relatively few changes from the last posting: In the case of CIP-004-7, the only significant change is the addition of a new requirement that responsible entities “implement one or more documented access management program(s) for [BCSI]” along with a table defining what such programs must consist of. Changes to CIP-011-3 include clarifying requirements for the reuse and disposal of BES cyber assets and for the components of entities’ information protection programs.
The latest posting also incorporates language previously agreed between the teams for Project 2019-02 and Project 2019-03 to address concern about potential overlaps between their projects. The conflict centered on risk assessments for cloud storage providers, which both groups saw as their domain; however, earlier this year the team for Project 2019-02 agreed to leave specific risk assessment language to the other team and keep its focus on broader questions of risk management. (See CIP Teams Compromise on Cloud Risk Assessment.)
CAISO named the head of the Bonneville Power Administration as its new chief executive Thursday, a move that could help further the ISO’s expansion of its Western Energy Imbalance Market and increase its regional influence.
Elliot Mainzer has led BPA since 2013. He will replace CAISO CEO Steve Berberich, whose tenure ends Sept. 30, CAISO and BPA said in concurrent statements. Berberich announced his plans to retire in February. (See Western RTOs ‘Imperative,’ Says Retiring CAISO CEO.)
Elliot Mainzer | BPA
“Elliot’s demonstrated success leading a large, complex power and transmission organization will serve CAISO, our customers and stakeholders well,” the CAISO Board of Governors said in a joint statement. “We are happy to have a leader so knowledgeable about integrating renewables and passionate about building on CAISO’s organizational strengths and momentum toward low-carbon electricity.”
Mainzer has been credited with expanding BPA’s efforts to integrate large volumes of wind generation, adding to the already immense hydroelectric resources in the Pacific Northwest. The federal power giant generates 23,000 MW of carbon-free electricity and operates 15,000 circuit miles of high-voltage transmission lines. Its footprint covers an area larger than France, encompassing the watersheds of the Columbia and Snake rivers.
CAISO is pushing hard to expand the real-time EIM to a day-ahead market, an effort that has proven controversial among some stakeholders, who worry about California’s control spreading across the Western energy landscape. (See EDAM Design Could Undermine Tx Rights, Critics Say.)
Mainzer has expressed his support for the expanded day-ahead market (EDAM) as a means to trade the growing amount of solar and wind power across state lines.
“It’s not going be enough to sell all this stuff on a five-minute market,” he told last year’s annual meeting of the Northwest and Intermountain Power Producers Coalition. (See NIPPC Members ‘Carry On’ Without Kahn.)
On Thursday, Mainzer said he looks “forward to working closely with our colleagues across the West to build on the success of the Western Energy Imbalance Market and further strengthen regional coordination and technology innovation.”
The BPA CEO is regarded by some as a bridge builder. In a blog post Thursday, Natural Resources Defense Council Energy Co-director Ralph Cavanagh praised Mainzer’s ability to keep an open mind while dealing with disparate interests and forming coalitions.
“CAISO is lucky to get him, as is a western and international constituency broader even than the one he has served so well at BPA,” Cavanagh wrote.
From Enron to CAISO
Mainzer, a San Francisco native, earned degrees from the University of California, Berkeley, and Yale University.
He joined Enron Corp. in the late 1990s, working as an analyst and establishing Enron’s renewable power desk in Portland, Ore., according to a detailed biography posted on CAISO’s website.
When Enron collapsed in 2002, after its market manipulation schemes wreaked havoc on California and CAISO during the electricity crisis of 2000/01, Mainzer segued into government service with BPA, headquartered in Portland.
At BPA, he served in a series of increasingly responsible management roles, including deputy administrator, and became acting administrator in 2013. In January 2014, U.S. Secretary of Energy Ernest Moniz named him administrator and CEO.
BPA has been criticized during Mainzer’s tenure for losing money and increasing rates while struggling to maintain its aging infrastructure. Its assets include 31 hydroelectric projects, such as the 7,079-MW Grand Coulee Dam, completed in 1941, and the 2,614-MW Chief Joseph Dam, built in the 1950s.
The agency supplies electricity to 143 electric utilities that serve millions of customers in Washington, Oregon, Idaho, Montana, California, Nevada, Utah and Wyoming.
Worried about renewing long-term contracts, BPA cut tens of millions of dollars from its annual budget and tried to hold the line on rate hikes.
“Through collaboration with our customers and partners throughout the region, we have worked hard to bend the cost curve and keep base power rates flat,” Mainzer said in a statement last year.
Mainzer has “served as administrator during a period of significant industry change,” BPA said in its statement Thursday. “In response, he led the development of BPA’s 2018-2023 strategic plan, which serves as a roadmap to sustain BPA’s financial strength, modernize BPA’s assets and system operations, provide competitive power products and services and meet transmission customer needs efficiently and responsively.”
Moving from one energy giant to another probably will boost Mainzer’s salary from six figures to seven.
Mainzer made about $245,000 in base pay and bonuses as BPA administrator in fiscal year 2018, BPA reported in response to a Freedom of Information Act request last year. Berberich earned nearly $1.5 million in 2017, according to CAISO’s most recent Form 990 filing as a nonprofit organization with the Internal Revenue Service.
Berberich plans to remain in Folsom through October to help with the transition, CAISO said.
American Electric Power CEO Nick Akins said Thursday that federal investigators have not contacted the company about an alleged bribery scheme tied to passage of Ohio House Bill 6, and he defended AEP’s contributions to a “social welfare organization” linked to the scandal.
“We are not aware of any information suggesting that AEP’s participation in the process was anything other than lawful and ethical,” he said in prepared comments during a quarterly earnings call with financial analysts. “Based on the facts that we know, we do not believe that AEP is [among] any of the companies specifically described in the [federal charges]. We have not been contacted by any authorities conducting the investigation. If at any point we are, we will cooperate fully.”
Akins said the company has contributed $8.7 million since 2015 to Empowering Ohio’s Economy, a 501(c)(4) nonprofit organized to promote economic and business development in Ohio. The contributions, he said, were ‘’appropriate and lawful,” and he noted that AEP has contributed to a variety of such organizations.
“We consistently advocate for policy positions that benefit our customers, communities and shareholders, and our advocacy of HB6 was no different,” he said. “We ultimately supported the legislation because we believe it maintained important fuel diversity for Ohio, including support for investments in renewables, nuclear generation and two [Ohio Valley Electric Corporation] coal plants.”
AEP owns 43% of OVEC.
Given “concerns that some have expressed regarding the lack of transparency surrounding 501(c)(4) organizations,” Akins said, AEP will commit to include[ing] additional disclosures about its contributions to the organizations in its 2020 corporate accountability report and going forward. Those nonprofits are not required to disclose their donors and the amount of donations.
“We also are reviewing best practices and working to improve our policies and processes around political contributions and contributions to 501(c)(4) entities,” he said.
The Columbus Dispatch, AEP’s hometown newspaper, reported in July that the company has contributed to Empowering Ohio’s Economy, which is part of a federal case that has led to the indictment of Ohio House Speaker Larry Householder and four associates on criminal charges. The nonprofit gave $150,000 to Generation Now, a dark money group that received $61 million from FirstEnergy interests to ensure HB 6’s passage, the Dispatch said. (See FirstEnergy, AEP CEOs Deny Wrongdoing.)
The legislation provided $1 billion in subsidies to a pair of coal plants in which AEP has a 43% stake and two nuclear plants. Businesses, legislators and ratepayers have all called for HB 6 to be repealed.
AEP’s headquarters building in Columbus, Ohio.
“We were surprised and disappointed to learn of what federal investigators allege was a scheme by the speaker of the Ohio House and others to enrich themselves, and we, along with you, have been trying to educate ourselves about the criminal complaint and the underlying conduct in it,″ Akins said.
The comments came the same day Householder and others were to be arraigned in federal court on racketeering and bribery charges. Householder’s hearing was delayed after he requested new legal representation.
AEP reported quarterly earnings of $521 million ($1.05/share), an increase from 2019’s second-quarter earnings of $461 million ($0.93/share).
The company’s stock price rose 54 cents during the day, closing at $84.83.
World Resources Institute researchers made an economic case this week for climate action, given the COVID-19 pandemic.
Dan Lashof, the global research firm’s U.S. director, said 41 states have managed to reduce their carbon emissions in recent years while simultaneously growing their economies. That discredits the maxim that economic growth must come at the environment’s expense, he said.
Maryland topped the list of states decoupling carbon emissions and economic growth between 2005 and 2017, according to WRI’s new research. The state cut emissions by 38% while growing its gross domestic product by 18% during the 12 years. New Hampshire, Alaska, Georgia, North Carolina and Indiana also made the top 10 in cutting emissions while growing their GDPs by at least 13%.
“It’s a false choice between shrinking emissions and growing the economy,” Maryland Secretary of the Environment Ben Grumbles said during an Aug. 4 WRI webinar.
WRI Research Associate Joel Jaeger said Northeastern and Midwestern states made the most progress cutting carbon while expanding their economies. On the other hand, he said, Texas, the Dakotas and the Gulf States have not made any progress on emission reductions. Idaho was ranked last, experiencing a 17% rise in emissions as its GDP rose by 22%.
Jaeger said states can use large investments in clean energy to help restore the nation’s pandemic-stricken economy.
Carbon emissions change 2005-2017 | WRI
Lashof said a $1 million investment in clean energy in the U.S. creates twice as many jobs in the medium- to short-term than $1 million spent on fossil fuels.
“This is an ideal moment to scale up manufacturing and export of various low-carbon technologies,” said WRI Senior Associate Devashree Saha. Low interest rates typical in recessions make it a “particularly good moment,” she said.
Saha estimated that states need “substantial, but manageable” investments in low-carbon infrastructure. She said the U.S. would need additional annual investments equivalent to about 2% of GDP.
“Even at 2%, that is well within the historical range,” she said. “Energy spending in the United States is at a low point now at around 6% of GDP but has fluctuated to as high as 13%.”
WRI maintains the investments would be money well spent.
“Ignoring climate change is expensive … Delaying action on climate change will further expose the United States to costly damages from climate impacts, air pollution and other public health crises,” Jaeger said, using the nation’s response to the COVID-19 pandemic as an example. He estimated that without new climate policies, the U.S. could encounter economic damages equivalent to anywhere from 1% to 10% of GDP/year by 2100.
To honor the Paris Agreement’s more ambitious target of limiting global warming to 1.5 degrees Celsius, the U.S. needs to cut net emissions by 40 to 50% from 2005 levels by 2030 and aim for carbon neutrality by 2050. WRI said that means U.S. emissions must drop more than twice as fast from 2018 to 2030 than they did from 2005 to 2018.
WRI staff said that can be done with strong federal climate policies, such as carbon pricing and more investment tax credits.
“I think the federal government can amplify these efforts,” Saha said.
FERC on Tuesday accepted most provisions in ISO-NE’s second compliance filing for Order 841, which requires RTO market participation rules to recognize the unique physical and operational characteristics of storage resources.
The changes become effective Dec. 3, 2019, with a limited number of revisions becoming effective Jan. 1, 2026, subject to further compliance filings (ER19-470-004).
The commission in December found ISO-NE had failed to comply with requirements to account for maximum run time, maximum charge time, state of charge, maximum state of charge and minimum state of charge (collectively, state of charge and duration characteristics) of electric storage resources in the day-ahead market. It required the RTO to modify its participation model through bidding parameters or other means.
FERC in April denied a rehearing request on the same issue. (See ISO-NE Order 841 Rehearing Request Denied.) In Tuesday’s order, the commission accepted most of ISO-NE’s revisions around the issue but found the RTO still didn’t go far enough.
Green Mountain Power’s Stafford Hill Solar Farm in Rutland, Vt was the first in the region to use battery storage to reduce peak demand. | UVM
“We find that, while ISO-NE’s proposed revisions state that it will account for such characteristics in the day-ahead market through bidding parameters or other means, ISO-NE has failed to propose any bidding parameters or other means through which it will do so,” the commission said.
“If ISO-NE intends to rely on new bidding parameters, it must define those bidding parameters in its Tariff and explain in its transmittal how those bidding parameters will be incorporated into its day-ahead market engine,” the commission said, directing the RTO to file such revisions within one year.
The commission also rejected ISO-NE’s response to direction that it file Tariff revisions that apply transmission charges to an electric storage resource when that resource is charging for later resale in wholesale markets and is not providing a service, and to include a basic description of ISO-NE’s metering methodology and accounting practices for ESRs.
“We disagree with ISO-NE’s statement that electric storage resources will always be providing a service when charging for later resale in the wholesale markets,” the commission said. “Specifically, we find that ISO-NE has failed to demonstrate that an electric storage resource that is self-scheduled to charge at a fixed MW quantity is providing a service that warrants exempting its full self-scheduled charging MW from transmission charges.”
The commission directed ISO-NE to file within 90 days Tariff revisions specifying that it will not apply transmission charges to ESRs when they are dispatched to withdraw energy to provide voltage support and reactive control, provide operating reserves, provide regulation, balance energy supply and demand on an economic basis or address a reliability concern, but it will apply transmission charges to ESRs when they are not being dispatched to provide one of those tariff-defined services.
The commission also directed the RTO to modify Tariff language that “could effectively allow the host utility to decide whether an electric storage resource may participate in the ISO-NE markets by stating that an electric storage resource cannot qualify to participate if the host utility is unwilling or unable to support the necessary registration, metering and accounting of the electric storage resource. This language may create a barrier to the wholesale participation of electric storage resources and may therefore be inconsistent with Order Nos. 841 and 841-A.”
Expressing concern over the bulk power system’s preparedness for a cyberattack, members of the Senate Energy and Natural Resources Committee on Wednesday pressed representatives from industry and the federal government to strengthen their cooperation.
King Focuses on Testing Gap
Senator Angus King (I-ME) | U.S. Senate
Testing utilities’ cybersecurity preparations was a major theme of the hearing, with Sen. Angus King (I-Maine) asking witnesses what work their organizations had done to verify the readiness of utilities’ systems.
“I was very disturbed a year or two ago when we had a hearing on this subject, and I asked the fellow from NERC, ‘Do you red-team, do you [penetration] test,’ and the answer was, ‘I don’t think so,’ or something to that effect,” King said, referring to testing practices where organizations hire professional hackers to try to break into their systems.
While Thomas O’Brien, senior vice president and CIO of PJM, assured King that the RTO frequently conducts penetration testing and red-team exercises, the senator was not so happy with the response of Alexander Gates, who earlier this year was picked to head the Department of Energy’s Office of Cybersecurity, Energy Security and Emergency Response (CESER). (See DOE Names Gates to Head CESER.) Gates said that while DOE conducts red-team exercises on federal property, the office serves a consulting role with regard to private sector organizations.
“Wasn’t CESER designed to protect the grid?” King asked.
Thomas O’Brien, PJM | U.S. Senate
“It’s designed to protect the grid, yes sir, but —”
“Isn’t [part of] protecting the grid determining whether it’s safe?” King broke in.
“We could do more, perhaps we should do more,” Gates admitted. “I don’t know if it gets to the level of pen-testing or red-teaming … but again, right now … with the responsibilities and authorities that we have, and the partnerships, it’s an advisory service that we’re providing at this point.”
King asked Gates to inform the committee if additional authorities would help DOE and CESER to strengthen their testing capability, reiterating that he “[didn’t] see how you can carry out a mission of protecting the grid without testing the grid’s vulnerability.”
Manchin Probes Communication Resiliency
Senator Joe Manchin (D-WV) | U.S. Senate
Sen. Joe Manchin (D-W.Va.) also grilled Gates and O’Brien on testing. The ranking member’s questions focused on utilities’ ability to maintain communications during cyber incidents.
Manchin first asked O’Brien whether PJM had any procedures in place for testing whether members have robust mechanisms for keeping essential data flowing to the RTO. Told by O’Brien that “we don’t feel [that] is in our jurisdiction,” Manchin asked Gates if DOE had made any effort to check on communications resiliency.
“If they’re actually not really hardening the systems to protect against the cyberattacks, how are you able to detect that?” Manchin asked. “Do you wait until something happens, or are you all checking to see if they’re doing it?”
“We’re not — there is a reporting mechanism in place —” Gates began.
Alexander Gates, Department of Energy | U.S. Senate
“No one’s checking, I can tell right now, no one’s testing to make sure,” Manchin interrupted. “If I wanted to find out if you did what you told me you did, I’d have one of my smart people try to hack in … and see if I showed a fallacy there. So we’re not doing those types of testing.”
Gates observed that the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA), along with FERC and NERC, do have “mechanisms to engage” with private utilities, but DOE is limited in its ability to oversee implementation of security guidelines. O’Brien concurred, telling Manchin that “we rely on … NERC compliance” and audits to ensure members are dealing with their vulnerabilities properly.
“Well, we’ll have to check with NERC, then, or check with somebody to see if somebody’s checking anything,” Manchin replied.
No one from NERC participated in the hearing.
Murkowski Urges Aid for Small Utilities
Senator Lisa Murkowski (R-AK) | U.S. Senate
Chair Lisa Murkowski (R-Alaska) reminded participants of the role that municipal utilities and rural electric cooperatives play in large parts of the U.S. grid. She asked Gates for an update on CESER’s efforts to help strengthen these smaller entities’ cybersecurity preparedness through grants and information sharing.
Gates did not provide any specific funding figures in response but reassured the committee that CESER is “working very hard” to ensure that small utilities and co-ops have the resources they need.
“The small utilities are … in some respects, the soft underbelly of the grid, and we take great pride in certain research and development programs … that we think are going to be valuable in providing those entities the same level of protection as some of the larger utilities,” Gates said.
Evergy confirmed Wednesday that it will remain independent and released details of the standalone plan that helped guide its decision.
CEO Terry Bassham told financial analysts during the company quarterly earnings call that Evergy’s Sustainability Transformation Plan “sets the stage for significant value creation and a strong future for Evergy and our stakeholders.”
The plan follows a “comprehensive, independent review” that began earlier this year and calls for $8.9 billion of capital investments in facility upgrades, grid modernization technologies and clean energy initiatives through 2024 in the company’s Kansas and Missouri service territory.
“Our plan creates a compelling value proposition for shareholders,” Bassham said. “Throughout the review, we were focused on three core objectives: maximizing long-term value for our shareholders, serving the best interests of all Evergy stakeholders, including our customers, employees and communities, and continuing to advance our work to successfully create a forward-thinking sustainable energy company.”
Evergy CEO Terry Bassham | Evergy
The Kansas City-based company had explored possible purchases by a number of other companies. It called off the effort to remain a standalone company. (See Report: EvergyCalls Off Sale, Stock Slides.)
Bassham said Evergy considered a potential strategic combination and a “modified, improved” standalone operating plan and strategy. The board of directors and its strategic review committee each retained independent financial advisors and consultants to assist in the review.
Asked by an analyst whether Evergy received any purchase offers, Bassham only said the company did “engage with a number of third parties” during a “robust and comprehensive process.”
“Without getting into a lot of the detail, in the end, the committee and the board both agreed that, based on that work and that review, our standalone plan produced a better long-term shareholder return profile and that was absolutely the best way to move forward,” he said.
Evergy has become the nation’s second-largest generator of wind energy as a percentage of total generation since 2005. The company has added or contracted for more than 4.6 GW of renewables and retired more than 2.4 GW of fossil generation. It said it can reduce CO2 emissions by 85% before 2030, compared with 2005 levels.
The company will benefit from recent Kansaslegislation that eliminates the state income tax for public electric utilities, effective Jan. 1. Bassham called the legislation “very positive” for Evergy’s customers and communities.
Evergy reported second-quarter earnings of $133 million ($0.59/share), compared with $140 million ($0.57/share) a year ago. The company’s operating earnings of $0.68/share just missed the Zacks consensus estimate of $0.70/share.
Evergy’s stock price lost 3.38% Wednesday, falling $1.87 before closing at $53.53.
NEPOOL members are trying to cull and combine nine proposals for the Transition to the Future Grid study that ISO-NE has offered to perform.
The New England States Committee on Electricity suggested ISO-NE build on the Pathway Scenario developed by the Northeastern States for Coordinated Air Use Management for achieving economy-wide carbon reductions. | NESCOE
ISO-NE CEO Gordon van Welie announced the initiative in March, saying it will give stakeholders information needed to plan transmission and market designs to achieve decarbonization goals. (See ISO-NE Study to Chart Transition to Future Grid.)
Representatives of each stakeholder group gave brief descriptions of their proposals and answered questions during a joint meeting of the NEPOOL Markets and Reliability committees Aug. 4.
In addition, Ben D’Antonio, counsel for the New England States Committee on Electricity, described NESCOE’s suggestion that ISO-NE build on the Pathway Scenario developed by the Northeastern States for Coordinated Air Use Management (NESCAUM) for achieving economy-wide carbon reductions. It assumes that at least 1,000 MW of clean energy resources will be added annually for the next several decades. NESCOE said the Pathway Scenario could be included in energy market modeling to generate hourly dispatch patterns, examine system operating characteristics and requirements and analyze transmission.
Day Pitney attorney Eric Runge presented a summary of the nine other proposals:
Eversource Energy asked for loss-of-load expectations (LOLE) and other reliability metrics, market prices, total cost to load, a description of how the supply mix could develop under current market rules and a qualitative assessment of how likely it is for such a supply mix to develop. It suggested three scenarios for meeting 80% economy-wide emission reductions by 2050: a mixed portfolio, a high offshore wind portfolio and a high solar portfolio. Eversource also made a second request to identify total installed nameplate capacity of a future system where LOLE meets the NPCC standard of one day in 10 years with no renewables built with out-of-market contracts clearing as new in the primary or substitution auctions.
National Grid asked how bi-directional controllable transmission with Quebec and other neighbors would impact emissions, LMPs and the use and spillage of intermittent resources. It also wants to identify transmission upgrades needed for a fully decarbonized economy and determine whether markets under high renewable/storage penetration cases would provide sufficient revenues to cover resources’ capital and operations and maintenance (O&M) costs.
Energy Market Advisors said the RTO should look at the cost, operational and resource adequacy implications of the two options available to new resources addressing state policy objectives: those using capacity network resource interconnection service (CNRIS) and participating in the capacity, energy and ancillary service markets and those using network resource interconnection service (NRIS) and participating in only the energy and ancillary service markets. If policy resources cannot get a capacity service obligation through the forward capacity auction due to the minimum offer price rule or the Competitive Auctions with Sponsored Policy Resources (CASPR) test price, or if the cost of a CNRIS is too high, EMA said that “NRIS may well become the preferred outcome.”
FirstLight Power said that to avoid understating potential reliability problems, the base scenarios should not assume significant new electric storage entry. It would add new electric storage based on as-modelled market prices, considering round-trip efficiency and variable O&M costs.
NextEra Energy and Dominion Energy made a joint request to determine how the loss of the NextEra’s Seabrook and Dominion’s Millstone nuclear power plants would impact market prices, system operations and state RPS targets and decarbonization goals.
American Petroleum Institute asked for a study on how the future grid will balance policy goals with other reliability, affordability and energy access objectives. API cited previous studies and reports by ISO-NE that it said demonstrate “that natural gas infrastructure can further economic and reliability objectives in the region.”
Multi-sector Group A (Acadia Center, Advanced Energy Economy, Brookfield Renewables, Conservation Law Foundation, Energy New England, Natural Resource Defense Council and PowerOptions) asked for an update and extension of the Planning Advisory Committee’s 2016 economic study on regulation, rampingand reserves to assess the impact of ramping, regulation and load-following resources as the system decarbonizes.
Multi-sector Group B (Advanced Energy Economy, Borrego Solar, Conservation Law Foundation, Energy New England, ENGIE, Natural Resources Defense Council and PowerOptions) seeks a long-term transmission system assessment to identify new transmission investments that could eliminate obstacles to reaching net zero-carbon and that are more economical than upgrades for near-term transmission needs. They also would like an analysis of whether distribution system generation, mobile and stationary storage, increased energy efficiency or flexible demand could reduce the need for new transmission.
Anbaric Development Partners called for identifying an onshore and offshore power system that is carbon-free by 2035, as proposed last month by Democratic Presidential candidate Joe Biden. (See Biden Offers $2 Trillion Climate Plan.)
The proposals called for study time frames of at least 10 years (EMA) to as long as 2050 (Multi-sector Groups A and B and Eversource).
Day Pitney will attempt to identify commonalities among the nine proposals before the committees’ next joint meeting on Sept. 1.
“It’s not definite at this point that we’ll be the ones conducting the study,” ISO-NE spokesman Matt Kakley said via email. “We’ve offered to do it if stakeholders want us to [and] we’re able, but it hasn’t yet been decided if that’s the direction stakeholders want to go. It’s still possible that a consultant could be hired for the work.”
E3/EFI Study
The committees also heard a presentation on a study on deep decarbonization by Energy+Environmental Economics (E3) and Energy Futures Initiative (EFI) that was funded by Calpine.
The study projects that electricity demand could nearly double over the next three decades with large additions of renewable generation, particularly solar and offshore wind.
The study included a “High Electrification” case in which 80% of building energy consumption is electricity, with about 230 TWh of annual load in 2050, a 97% increase. It also included a “High Fuels” scenario in which advanced biofuels and hydrogen result in somewhat lower electrification rates and greater reliance on low-carbon fuels, with about 60% of building energy consumption from electricity. It would have a load of 192 TWh by 2050, a 66% increase.
Energy+Environmental Economics (E3) and Energy Futures Initiative (EFI) conducted a study that looked at two scenarios for electrification and decarbonization that project electric load will increase by at least 66%. | E3/EFI
The New England electricity system becomes winter-peaking in the 2030s, and the median gross load peak (net of energy efficiency) is expected to increase from 25 GW in 2019 to 42-51 GW by 2050.
The study identifies land and transmission availability as likely constraining factors for new generation development. Its base case estimates that a land area equal to 4% of the region’s farmland will be needed for solar generation and 2% of farm and forest land needed for wind.
E3 and EFI said that New England will require 30-37 GW of thermal capacity through 2050 under all scenarios studied but that its usage will drop over time, with the capacity factors for gas-fired generation dropping to 10% to 15% by 2050. They expect some form of low-carbon fuel will be available to reduce the carbon intensity.
The E3/EFI study projected prices increasing by 38% by 2050, mostly due to new generation and transmission. | E3/EFI
The study found that cases with the most available solutions have lower costs and lower technology risks. Increasing the availability of land-based wind and solar also reduces costs.
“Firm, low-carbon technologies such as advanced nuclear, [carbon capture and sequestration] or hydrogen could play a significant role,” E3 and EFI said.
Average electric rates will increase at a compound annual growth rate of 1.3% to 1.5% by 2050 to fund infrastructure additions, including new generation, transmission upgrades and spur line costs, and a slight increase in variable costs. Average prices are forecast to rise from $0.17/kWh in 2025 to $0.23/kWh in 2050 under the high electrification case, an increase of 38%.
Mid-century economy-wide GHG emission reduction targets in New England | E3/EFI
Removing all combustion turbines (CTs) and combined cycle plants (CCGTs) increases the cost of achieving a zero-emissions grid by about $19 billion annually relative to a zero-emissions portfolio with zero-carbon fuels (hydrogen or biogas).
In most weeks, wind and solar generation minimizes the need for CTs, CCGTs or steam turbine generation. But when renewable production is low, up to 32 GW of thermal generation could be dispatched for reliability. Building a system with no gas or hydrogen would cause a “significant overbuild” of renewables and storage, resulting in many curtailments during typical weeks, the authors said.
Without upgrades to the region’s 345-kV network, the study found enough “headroom” for a combined 800 MW of renewable generation in New Hampshire and Vermont, and 4 GW each for Connecticut, Massachusetts and Rhode Island. There is no headroom for Maine, which has the best onshore wind potential in the region. Offshore wind headroom is estimated at 8 GW.
Utility-scale solar could increase to 50% of the projected 2050 peak load without upgrades. Reaching 100% would require 115-kV line upgrades.
Brattle Offshore Wind Study
It concluded that the current approach — with OSW developers competing primarily on cost to develop offshore generation and project-specific generator lead lines — would be more expensive than developing transmission independently from generation. “A planned approach is likely to result in lower costs in both the near- and longer-term, by lowering risks and costs of onshore upgrades and increasing competition for both offshore transmission and generation,” the study found.
The study also concluded that a planned approach would make better use of limited onshore points of interconnection, reduce seabed disturbances, increase competition for transmission and generation and reduce transmission upgrade costs.
Current generator lead line approach (left) vs. planned offshore-grid approach (right) | The Brattle Group
The study found that the region will need to add more than 1,500 MW of OSW annually to reach the “80% by 2050” decarbonization goals.
Comparison of total onshore plus offshore transmission costs in Phase 1 analysis (3,600 MW additional OSW) | The Brattle Group
Phase 1 of the study focused on 3,600 MW of OSW (including authorized procurements of 1,600 MW in Massachusetts and 1,200 in Connecticut). Phase 2 included an additional 4,800 MW, for a total of about 8,400 MW.
It cited as examples of proactive transmission planning Texas’ Competitive Renewable Energy Zones, California’s Tehachapi wind, MISO’s Multi-Value Projects and several European countries.
Brattle said the existing approach for connecting 2,800 MW of OSW already contracted to Cape Cod will require $131 million to $787 million in onshore transmission upgrades. Continuing the current approach in the next 3,600 MW of procurements could cost up to an additional $1.7 billion in onshore upgrades it said.
The planned approach would increase offshore transmission equipment costs by $600 million ($3.3 billion vs $2.7 billion) but reduce costs of onshore upgrades from $1.7 billion to $550 million, a savings of more than $1.1 billion or 10% for Phase 1.
Among other findings, Brattle said the planned approach would result in:
A 40% reduction in line losses.
Increased competition: It cited studies of offshore transmission costs in the U.K. showing that competition among independent offshore transmission owners reduced costs 20-30% compared with generator-owned transmission.
Fewer system overloads: The study said a scenario using the current planning, with 8.1 GW of generation and five points of interconnection, would have many more system overloads — particularly in Connecticut and the Mystic-North Cambridge-Woburn section of Massachusetts — than a planned system that carried 8.6 GW over nine points of interconnection.
Lower OSW curtailment: 14% vs. 34% in 2028.
Increased production cost savings: $619 million in 2028 vs. $564 million for the current process, a difference of $55 million or almost 10%.
Lower LMPs: Some locations in Rhode Island and Southeastern Massachusetts would face significantly higher LMPs by 2028 under the current approach because of transmission congestion.
An almost 50% reduction in marine trenching: 831 miles vs. 1,620 miles for Phases 1 and 2.
Preservation of the option for networked transmission to improve reliability and reduce curtailments from transmission outages: If three 1,200-MW HVDC converter stations were networked offshore, an outage of one line would still allow full power flow in all hours when total generation is less than 2,400 MW, resulting in only 4% of energy curtailed relative to no outages. “Under the current (non-meshed) gen-tie approach, an outage in any one of three lines would [result in a] 33% reduction in delivered energy to the onshore system, causing significantly more curtailments than under a meshed configuration,” Brattle said.
NERC’s Reliability Issues Steering Committee (RISC) is planning to bring forward the release of its next ERO Reliability Risk Priorities Report — traditionally published in November of odd-numbered years — to August 2021. The biennial Reliability Leadership Summit will be held earlier next year as well — in January – rather than its usual time in March.
Presenting the expected publication schedule to RISC members via conference call on Thursday, Thomas Coleman, director of risk issue management at NERC, said an August release seemed more “timely” than the traditional November publication date. Work on the report is expected to begin in the fourth quarter of 2020 with the production of the risk template and the release of the industry survey to “prioritize identified risks as well as to potentially identify new and emerging risks.”
Results of the survey will form the basis of discussions among industry leaders at the Reliability Leadership Summit. The last summit, held in March 2019, involved more than 130 regulators, utility officials, RTO executives and other stakeholders. (See NERC Chief: No ‘Appetite’ for Expanding Authority.) The format of next year’s summit has not been finalized, but Coleman said that “more than likely” the meeting will be held online.
“I think we can really have a very interactive and productive [summit] virtually,” he said. “We’ve all been on so many different variations of virtual calls, [and] we’ve seen some really innovative and creative approaches, so I feel strongly that we can develop a really meaningful and impactful virtual meeting in the beginning of 2021.”
Risk Framework Goes to RSTC Next Month
RSTC/RISC coordination within the risk mitigation framework. | NERC
NERC Chief Engineer Mark Lauby updated the committee on NERC’s planned risk mitigation framework, which is currently under development with input from the Reliability and Security Technical Committee (RSTC). The committees hope to finish the framework in time to present it to NERC’s Board of Directors at its November meeting.
Development of the framework began last year in hopes of creating a unified, transparent process to help entities choose the best approach to manage various situations. (See NERC Developing Risk Mitigation Framework.) A preliminary framework was created by the ERO Enterprise with input from the North American Transmission Forum and handed off to RISC for further refinement after the February board meeting.
The latest updates to the framework focus on the relationship between the RSTC and RISC in the risk mitigation process, including a flow diagram that breaks down each committee’s responsibilities at each stage. RISC plans to pass the document to RSTC by Aug. 19 for inclusion in the agenda for its meeting next month. Once RSTC members have provided their input, the committees will finalize the document so that RISC Chair Nelson Peeler and RSTC Chair Greg Ford can present it to the board together.
“What we’d like to do, depending on the views of everyone, is ultimately take this to the board as a joint [proposal], so that it kind of puts a little bit more cement around how we identify and prioritize risks and work on risks in a more formal way,” Lauby said.
RISC Charter Updates Accepted
RISC members also voted to approve proposed changes to the committee’s charter and submit them for acceptance by NERC’s board at its November meeting.
The approved edits are largely cosmetic, aimed at replacing outdated language and aligning the charter with those of other NERC committees. However, Jennifer Sterling of Exelon said she was concerned that the committee would have just one representative from the RSTC, as opposed to one each from the Operating, Planning and Critical Infrastructure Protection Committees that the RSTC replaced earlier this year. (See RSTC Tackles Organization Issues in First Meeting.)
Sterling asked if RISC would be able to achieve the same level of coordination with RSTC as its predecessors with fewer shared members. In response, Peeler said that RISC leadership felt one RSTC representative would be enough to maintain communication, especially since the two committees plan to create more formal bonds going forward.
“The purpose of those committee members being on RISC was for them to maintain alignment and bring issues from their committees, not necessarily to be the technical expert of the committee,” Peeler said. “[But] we’re going to have more coordination between RSTC and RISC formalized … in the framework.”
Consolidated Edison said Thursday that the COVID-19 pandemic had negatively impacted its first-half earnings by $52 million — a report that came as the utility struggled to restore power to its more than 500,000 customers in and around New York City after Tropical Storm Isaias hit two days earlier.
