Fossil energy will continue to play a major role in the U.S. for years to come, President Biden’s nominee for secretary of the interior, Rep. Deb Haaland (D-N.M.), told the Senate Energy and Natural Resources Committee on Tuesday.
Haaland said that she recognizes not only the importance of oil and gas reserves to local economies, but also the need to address climate change. She committed to working cooperatively with Congress and stakeholders to strike “the right balance” between those issues.
Several Republican committee members expressed concern that statements Haaland made in the past against fracking and pipelines and in favor of clean energy are demonstrative of how she would lead the Department of the Interior.
Haaland claimed to be “the highest-rated freshman in Congress on bipartisan collaboration” as evidence of her willingness to work across the aisle on the difficult issues their constituents face in the energy transition. When pressed whether she personally supports a ban on oil and gas, Haaland said that she would support the president’s agenda, not her own, in the role as secretary.
“I realize that serving as a cabinet secretary is far different from being a member of Congress, where I’m representing one district,” she said. “It’s representing every single American, and I recognize that there is a difference in those two roles.”
The ENR Committee adjourned Tuesday and scheduled a second session for the hearing at 10 a.m. on Wednesday.
President Biden’s nominee for secretary of the interior, U.S. Rep. Debra Haaland (D-N.M.), spoke at her Tuesday confirmation hearing about the importance of her nomination as a Native American. She is seen here meeting with members of the National Guard in January. | U.S. Rep. Debra Haaland via Twitter
Making History
Haaland said the significance of being the first Native American nominated for interior secretary was not lost on her.
Several committee members also acknowledged the milestone.
Sen. Catherine Cortez Masto (D-Nev.) | Senate ENR Committee
“I recognize, as a member of [the Senate Committee on] Indian Affairs, the historic nature of your nomination as the first Native American woman nominated by the president to lead the Department of Interior,” Sen. Catherine Cortez Masto (D-Nev.) said.
Sen. Mazie Hirono (D-Hawaii) noted how important it is that Haaland is a 35th generation Pueblo, which means, she said, “that your people were in our country long before the rest of us ever came here.”
Sen. John Hoeven (R-N.D.) took the opportunity to test Haaland’s commitment to Native American tribal interests as they relate to the fossil fuel industry.
Hoeven said Haaland protested Energy Transfer Partners’ Dakota Access oil pipeline and asked if she was still opposed to it. The pipeline was placed into service despite high-profile protests that started five years ago.
Sen. John Hoeven (R-N.D.) | Senate ENR Committee
“Yes, I did go to stand with the water protectors during that [protest],” Haaland said. “The reason I did that is because I agreed with the tribe that they felt they weren’t consulted in the best way.”
Members of the Standing Rock Sioux Tribe said that siting of the pipeline under a lake near their reservation threatened water quality.
Hoeven pressed Haaland on her current position on the status of the pipeline, which is under environmental review again following a ruling last March by the D.C. District Court.
“Whenever these projects come up, we absolutely should make sure that we are consulting with tribes if, in fact, these projects do affect their lands and their sacred sites,” she said.
Hoeven asked Haaland if she would recuse herself from matters related to the pipeline that come before the department to avoid a conflict of interest. Haaland answered that she would heed the advice of department attorneys on any potential conflicts.
The developer of a proposed offshore wind project in New Jersey has signed an agreement to employ union workers in the project’s construction and operation.
The memorandum of understanding between Atlantic Shores Offshore Wind and the unions could create hundreds of temporary and permanent jobs, said Julia Ofman, a spokesperson for the company, which is a joint venture between affiliates of the Anglo/Dutch oil giant Shell and France’s EDF.
Atlantic Shores is competing with Denmark-based Ørsted in the New Jersey Board of Public Utilities’ second OSW solicitation, which is seeking 1,200 to 2,400 MW. (See New Jersey BPU OKs 2nd Offshore Wind Solicitation.) The BPU expects to announce the winner in the second quarter, with commercial operation set for 2027.
In 2019, the BPU selected Ørsted’s 1,100-MW Ocean Wind project in its first solicitation. Construction of Ocean Wind, 15 miles off the coast of Atlantic City, is expected to begin next year, with commercial operation in 2024. The BPU says Ocean Wind will generate $1.17 billion in economic benefits for the Garden State and create more than 15,000 jobs over the 20-year life of the project.
Ørsted said its bid in the second solicitation, for what it’s calling Ocean Wind 2, included “continued engagement with local unions and support for efforts to create a well-trained offshore wind workforce.”
Asked for an update, the company noted its November announcement of an MOU with North America’s Building Trades Unions covering all Ørsted projects under development and any future projects on the Eastern Seaboard.
“We’ve made a long-term commitment to building our portfolio of projects, both onshore and offshore, with union labor,” the company said in a statement to RTO Insider. “We’re working with unions, at both the national and local level, to develop workforce training programs that will prepare their members for the robust opportunity that offshore wind presents. Perhaps most importantly, all Ørsted projects will be constructed under collectively bargained labor agreements, inclusive of all trades necessary for both onshore and overwater construction scopes.”
Atlantic Shores holds a 183,353-acre lease area (OCS-0499) about eight miles off the coast of Atlantic City, with capacity for 2,500 MW of OSW. It is north of Ørsted’s 160,480-acre lease area (OCS-0498).
The six unions included in the MOU with Atlantic Shores are Eastern Atlantic States Regional Council of Carpenters; Laborers’ International Union of North America; International Brotherhood of Electrical Workers Locals 456, 400 and 351; International Union of Operating Engineers Local 825; Ironworkers International; and the Eastern Millwright Regional Council.
Atlantic Shores said the MOU “is the strongest commitment to date by a United States offshore wind developer to train local residents and tradespeople and use union labor and employers wherever possible.”
“Union labor helped to build New Jersey, and if our bid is selected, union labor will be central to building its renewable energy infrastructure and sustainable future,” Joris Veldhoven, commercial director at Atlantic Shores, said in a press release.
The agreement includes a commitment to create OSW training and apprenticeship programs and to “further integrate union workers” into the OSW workforce by encouraging suppliers and contractors to sign labor agreements.
Atlantic Shores also pledged in its bid to fund clean energy start-ups in the Minority & Women Owned Business Incubator at the Rutgers EcoComplex in Bordentown, N.J. It will also back 30 yearly scholarships for Rowan College at Burlington County’s certificate programs in Energy Industry Fundamentals and Transportation, Logistics and Distribution/Supply Chain, as well as training for entry-level manufacturing machinists.
According to the research firm Rystad Energy, demand for OSW employees will triple by the end of the decade, surging to 868,000 full-time jobs from an estimated 297,000 in 2020. The Bureau of Labor Statistics says wind turbine technician jobs are expected to grow 61% through 2029 – faster than any other job category. The jobs paid a median annual wage of $52,910 in May 2019.
New Jersey has targeted procurement of 7,500 MW of OSW in the next 15 years as part of its goal to reach 100% clean energy by 2050. The BPU plans to open a third solicitation for at least 1,200 MW of OSW capacity in the third quarter of 2022. (See NJ Sets Schedule for OSW Procurements.)
Wisconsin Gov. Tony Evers’ (D) second state budget seeks millions in funding to make good on the commitment he made a year ago to address climate change. However, the policy measures he proposed to put the state on a path to 100% carbon-free electricity by 2050 will likely meet the same fate as his 2019 climate agenda, which was cut out of the budget by the Republican-controlled legislature.
Evers joined the U.S. Climate Alliance of governors pledging to support the carbon reduction goals of the Paris climate accord shortly after taking office in 2019. He narrowly defeated Republican Gov. Scott Walker, ending an eight-year administration which rarely mentioned “climate change” except to deny its existence.
“We made a commitment to make Wisconsin 100% carbon-free by 2050, and we’re going to keep it,” Evers said in his budget address Feb. 16. “Our utility partners have made great strides this year toward reducing emissions, but we still have a long way to go. … It is critical that we take necessary and immediate steps to address energy production and efficiency.”
Wisconsin Gov. Tony Evers, shown giving his budget address, is attempting to make progress on his climate agenda despite Republican opposition. | Gov. Tony Evers
The commitment to a carbon-free future was stripped from the governor’s proposed 2019-2021 state budget by the Republican leadership of the Joint Finance Committee. Also nixed was the creation of an Office of Sustainability and Clean Energy within the Department of Administration.
And Evers’ chances don’t look much better this year. Republican Assembly Speaker Robin Vos dismissed his climate agenda and other budget proposals as “nothing more than a liberal Democrat from Madison’s wish list to his donors.” The budget must be approved by July 1.
After a series of public meetings, the 32-member task force, chaired by Lt. Gov. Mandela Barnes, issued a 120-page report in December offering 55 recommendations related to energy, transportation, agriculture, education, forestry, food, jobs and environmental justice.
All but 10 of the proposals would require legislative approval or inclusion in the state budget.
“We’re excited about Gov. Evers’ budget proposal. It has a lot of really ambitious agenda items that reflect what people have been asking for,” said Heather Allen, executive director of RENEW Wisconsin, a nonprofit promoter of renewable energy. “There are areas of compromise that recognize the economic benefits of renewable energy for the state.”
Allen said there is support across the aisle for some aspects of the governor’s climate change agenda — such as funding for job training in the fields of renewable energy and energy efficiency through the Wisconsin Fast Forward grant program.
“We need to increase the number of Wisconsinites trained in those jobs,” she said. “We’re optimistic there’s bipartisan support for this.”
Allen is also hopeful Evers will win support for his proposal to double utility companies’ funding of the Focus on Energy program, which has been frozen since 2010. Doubling the funding from 1.2% to 2.4% of annual operating revenues would generate an additional $100 million for energy programs for low-income residents and investments in renewable energy.
“This program is actually where Wisconsin is a leader. Focus on Energy has proven very effective in funding energy efficiency and renewables,” Allen said. “We would love to see deeper investment there and an expansion of the program into new areas like electric vehicles and beneficial electrification. These are definitely things we think both parties can get behind.”
Wisconsin Republican legislators are expected to refuse to fund Gov. Tony Evers’ programs addressing climate change in the 2021-2023 budget. | Shutterstock
One recommendation not requiring legislative approval is having the state lead by example: committing agencies and buildings to switch to clean energy use. The University of Wisconsin-Platteville, for instance, won approval in early February to build a 2.4-MW solar array. The infrastructure could save the campus $200,000 annually after it is built later this year.
“More and more projects like that coming online through the governor’s leadership will demonstrate the value of renewable projects for the state just from the bottom-line perspective,” Allen said.
The governor also doesn’t need the legislature to endorse the carbon-reduction goals of the state’s utility companies. Alliant Energy, WEC Energy Group and Xcel Energy have all made public their significant plans to shift away from coal and gas for generating electricity over the next couple decades. Alliant is investing $900 million in clean energy production, including the purchase of several solar farms.
Another move Evers could make unilaterally is to compel the Public Service Commission to modernize and standardize the rates paid to customers who generate renewable energy — everyone from homeowners with rooftop solar panels to manufacturers and institutions which can independently produce several megawatts of clean energy. Many renewable energy generators are competitively disadvantaged by the current system that allows individual utilities to set rates that should be uniform across the state, RENEW says.
Evers’ budget includes the task force’s call for funding of a statewide climate risk assessment and resilience plan and technical assistance for municipalities and tribal communities to plan to be carbon-free by 2050. Evers would also fund a new Office of Environmental Justice with $200,000 over its first two years.
The governor’s wish list includes $100 million in bonds for energy conservation projects on state property, such as the University of Wisconsin System; $30 million spent on flood prevention measures and infrastructure; $10 million from the state’s portion of the Volkswagen emissions settlement to reinstate an electric vehicle charging station grant program; and $700,000 to replace aging state vehicles with electric ones.
“The climate crisis is taking an undeniable toll on folks across our state,” Evers said in his budget address. “Every Wisconsinite — whether they live in the Driftless, the Central Sands, or the Northwoods, or in the heart of our urban areas — has experienced the effects of climate change. And communities of color, low-income Wisconsinites, and our farmers have been among those most disproportionately affected.”
Public utility commissions’ executive leadership must be willing to take a “champion” role in building their organizations’ cybersecurity expertise, according to a guideline released this week by the National Association of Regulatory Commissioners.
NARUC created the guide to recognize the growing importance of electronic communication tools to utilities in their everyday operations. The proliferation of innovative technology throughout the grid has made it easier than ever for system operators to track and respond to disturbances in real-time, but also created many new points of access for malicious cyber actors seeking to damage critical infrastructure.
The problem was highlighted by the discovery last year that hackers linked to Russia’s military gained access to computer networks used by thousands of public- and private- sector organizations. Earlier this year SolarWinds Recovery May Require Extreme Actions.)
Utilities must bear the cost of preventing future breaches, or mitigating their damage, by setting up robust cyber protections. However, PUCs cannot afford to sit idle; they will need their own cybersecurity experts, both to make sure their own defenses are capable of shielding vital information and ensure that power providers’ measures are suitable.
“We must weigh the costs and benefits of utilities’ cybersecurity investments. And should the day come, we must be ready to work with our utilities to recover from a successful cyberattack. To perform these functions, access to cybersecurity expertise is vital,” Pennsylvania PUC Chair Gladys Brown said in the document’s foreword.
Multiple Organizational Models
The NARUC guide draws on previous work, such as the organization’s Cybersecurity Strategy Development Guide from 2018, while expanding on two key areas: organizational approaches for PUCs’ cybersecurity divisions and guidelines for hiring and retaining cyber talent.
Setting up a cybersecurity department may seem like a daunting task for commission staff, particularly if they have spent most of their careers focused on utilities and find themselves playing catch-up in the world of electronic defenses. This is why executive-level buy-in is so critical: PUC leaders must set a clear goal for the new project, lay out how it aligns with the commission’s mission, define how the newly hired professionals will fit into the existing structure and ensure they are treated equally to veteran employees.
Job openings by National Initiative for Cybersecurity Education cybersecurity framework category, June 2019-May 2020 | NARUC
“In some PUCs, [cybersecurity experts] exclusively have external utility-facing roles; in others, they may only secure PUC-specific IT infrastructures, and in others, they may perform both functions,” the report states. “It is worth noting that in some PUCs, cybersecurity may not be a full-time role; rather, it may be part of a more extensive umbrella of critical infrastructure and risk management work.”
PUC leaders must also keep their available resources in mind when laying out organizational plans, including budgetary constraints that might keep them from employing their own full-time cybersecurity professionals. The guide suggests several alternative organizational models to dedicated in-house cyber divisions, such as a mix of internal and outsourced operations or adding cybersecurity responsibilities to an existing division. However, the organization emphasized that “many effective variations of these models exist.”
Recruitment and Retention
Budgetary factors may also strain a PUC’s ability to attract and retain the needed level of cybersecurity talent, particularly given the high demand for security professionals among all organizations. The report notes a 2019 study that suggests the U.S. needs to expand the cybersecurity workforce by 62% to meet demand, with more than 900,000 individuals already working in related professions between May 2019 and June 2020, but over 500,000 positions are still unfilled.
Organizational models for PUC cybersecurity divisions | NARUC
Because it may be tough for PUCs to match salaries offered in the private sector, NARUC suggests playing on different motivators to entice cybersecurity experts. Attractive aspects to employment with PUCs for entry and mid-level professionals include the security of a government job, a positive work/life balance compared to the private sector and a “sense of civic duty” that comes from serving one’s fellow citizens. For director-level candidates, NARUC suggests portraying the position as a chance to tackle new challenges and enter a second career phase.
Keeping skilled professionals on board is another challenge for commissioners because rapid turnover means private sector organizations are always looking for new talent. The report recommends showing employees that their suggestions and concerns are taken seriously, giving them opportunities for ongoing training and providing reliable pathways for advancement to higher levels.
“There is no ‘default’ cybersecurity expert or single skillset that applies to cybersecurity broadly,” the report says. “When hiring, PUCs must carefully consider their state’s cybersecurity strategy, their own cybersecurity strategy, the roles and responsibilities that a cybersecurity professional will undertake and the essential skills necessary to perform them.”
The blame game over last week’s lengthy outages in Texas that left millions without power has left five out-of-state members of ERCOT’s Board of Directors, including new Chair Sally Talberg, falling on their swords.
In a letter the grid operator filed Tuesday with the Texas Public Utility Commission, Talberg and three independent directors said they are resigning from the board after tomorrow’s emergency teleconference with ERCOT “to allow state leaders a free hand with future direction and to eliminate distractions.”
In a footnote in the filing, the grid operator said Just Energy’s Vanessa Anesetti-Parra, who represents the independent retail electric provider market segment, will also resign from the board after Wednesday’s meeting. ERCOT also said the nominee for the last of its five independent director positions has withdrawn his application.
A CPS Energy crew works to restore power in San Antonio following last week’s winter storm. | CPS Energy
“We have noted recent concerns about out-of-state board leadership at ERCOT,” Talberg and the other independent directors said in the letter, which was addressed to their fellow directors.
The letter acknowledged “the pain and suffering of Texans during this past week,” when more than 4 million customers were out of power for hours at a time that led to dozens of deaths. ERCOT said it was “seconds and minutes” away from a total collapse of the grid when it shed 20 GW of load on Feb. 15. (See With Crisis Behind it, ERCOT Now Faces the Music.)
Talberg last week called for an urgent meeting to review the “sustained power outages” and staff’s preparations and decisions. ERCOT executives will also appear before a joint hearing of two Texas House of Representatives committees on Thursday.
“With the right follow-through, Texas can lead the nation in investing in infrastructure and emergency preparedness to withstand the effects of severe weather events,” the directors’ letter said. “We want what is best for ERCOT and Texas.”
The directors recognized ERCOT CEO Bill Magness and the staff for their hard work and dedication.
“The organization is filled with highly specialized, dedicated professionals who bring decades of experience to Texas,” they said. “We have only one thing to ask those of you who remain on the board: Please continue to recognize the fine people at ERCOT and what they do for Texas every day.”
“We look forward to working with the Texas Legislature, and we thank the outgoing board members for their service,” ERCOT said in a statement.
Jeff Dennis, general counsel for trade association Advanced Energy Economy, tweeted that “scapegoating ERCOT’s board here is absurd.”
“To make ERCOT’s leaders targets now (including one who is unquestionably brilliant and has barely been on the board a month) infuriates me,” he said. “ERCOT’s leaders have spent many years implementing a unified vision in Texas for electricity competition. In my experience, that unified vision among politicians, regulators, grid operators, etc., is [incredibly] rare.”
ERCOT’s bylaws require the board to have 16 directors, with five voting members classified as “unaffiliated,” or independent. The chair and vice chair are both required to be independent.
A seven-year member of Michigan’s Public Service Commission and twice its chair, Talberg was only elected as the board’s chair on Feb. 9. Her predecessor, nine-year Chair Craven Crowell, also lived out of state. (See Former Mich. Regulator Talberg to Chair ERCOT Board.)
Talberg does have Texas ties, having gained her master’s degree from the University of Texas at Austin. While in school, she worked with both the PUC and Lower Colorado River Authority.
She has 25 years of experience in energy and environmental regulatory policy. As a commissioner in Michigan, Talberg served on various state, regional and national boards and committees, including a term as president of the Organization of MISO States.
Joining Talberg in signing the letter and resigning were:
Peter Cramton, a board member since 2015 and the newly elected vice chair. An economics professor at the University of Cologne and the University of Maryland at College Park, he has researched auctions and market design for 37 years, focusing on complex markets. He has advised numerous governments on market design and dozens of bidders in major auctions.
Terry Bulger, a three-year board member with more than 35 years of banking experience and more than 25 specializing in risk manager. Bulger was to begin a second term in March.
Raymond Hepper, a first-year director who retired from ISO-NE in 2018 as its general counsel and corporate secretary. After spending most of the 1980s litigating complex tax cases for the Department of Justice, he settled into the utility industry in 1989.
Anesetti-Parra, who resides in Ontario, Canada, has more than 19 years of experience in retail energy. Vice president of regulatory and compliance for Just Energy, she has also worked for Universal Energy and Direct Energy.
ERCOT said that former Consolidated Edison CEO Craig Ivey had withdrawn his application to fill the fifth independent director’s position on the board. Ivey’s nomination had been sent to the PUC for final approval. (See “Con Ed CEO Nominated to Board,” ERCOT Board of Directors Briefs: Oct. 13, 2020.)
“When Texans were in desperate need of electricity, ERCOT failed to do its job, and Texans were left shivering in their homes without power,” Gov. Abbott said in a statement. “The lack of preparedness and transparency at ERCOT is unacceptable, and I welcome these resignations. The state of Texas will continue to investigate ERCOT and uncover the full picture of what went wrong, and we will ensure that the disastrous events of last week are never repeated.”
In a twist of irony, Texas Public Utility Commission Chair DeAnn Walker found herself sitting in a chilly, darkened hearing room Sunday as she opened the commission’s second emergency open meeting of the weekend.
The state’s facilities group had turned down all the heating and nearly all the lights — except for safety lighting — in government buildings following last week’s power outages, Walker explained.
The PUC then set about its business, issuing a set of orders intended to protect Texas electricity customers and prevent possible disconnections for non-payment on Monday. The directives immediately suspended disconnections until further notice and extended a COVID-19 measure that requires retail electric providers (REPs) to offer deferred payment plans upon request.
The orders only apply to customers of investor-owned utilities under the PUC’s jurisdiction: American Electric Power Texas, CenterPoint Energy, Oncor and Texas-New Mexico Power.
PUC Chair DeAnn Walker convenes the open meeting Sunday with only safety lighting. | PUCT
The commissioners also urged REPs to delay invoicing for residential and small commercial customers. The IOUs rely primarily on automated meters that, in the case of a long-term outage, estimate meter reads based on historical usage.
“We may end up doing this every day,” Walker warned her fellow commissioners. “Every day, a new rock may be turned over that requires us to take action.”
On Friday evening during a hastily called meeting, the PUC waived deadlines surrounding its provider-of-last-resort (POLR) program, where REPs volunteer to accept customers from other providers exiting ERCOT’s competitive market. These “volunteer” REPs are required to charge a competitive rate, rather than the higher POLR rate.
The move was driven by concern that some of the more than 100 REPs in the market may go under after wholesale prices reached $9,000/MWh during the cold snap and stayed there for much of the time.
“I’m happy these customers will have a place to go,” Commissioner Arthur D’Andrea said. “I don’t want any of them to get on a bad POLR plan. They shouldn’t have to deal with that now.”
Vistra’s TXU Energy and NRG Energy’s Reliant Energy, which together account for more than 70% of the retail market, are likely to benefit from the changes.
Horror stories abound of four-figure bills hitting customers who signed up with REPs that pass on wholesale real-time prices. Griddy grabbed most of the headlines by serving one customer a $16,752 bill.
The company’s CEO, Michael Fallquist, said Griddy was designed for an energy market that “allows consumers the ability to plan their usage based on the highs and lows of wholesale energy and shift their usage to the cheapest time periods.”
Griddy’s CEO shared a message sent to customers alerting them to high rates. | Griddy
Indeed, Griddy did warn its 29,000 customers as the winter storm approached to consider switching to other REPs.
For its part, TXU Energy assured its residential customers that they would not see any “near-term impact” because of the winter weather event, though some might experience above-normal bills because of higher usage.
“The headline-grabbing sky-high bills are related to wholesale plans offered by some providers; TXU Energy does not put its customers at risk by offering these plans,” TXU President Scott Hudson said in a statement.
On Saturday, Texas Gov. Greg Abbott convened a bipartisan virtual meeting with 11 state legislators to begin discussions on how to insulate customers from electricity plans linked to wholesale prices.
“It is unacceptable for Texans who suffered through days in the freezing cold without electricity or heat to now be hit with skyrocketing energy costs,” Abbott said before the meeting.
“Our absolute top priority as a commission and a state is protecting electricity customers from the devastating effects of a storm that already affected their delivery of power,” Walker said.
ERCOT, MPs Hit with Lawsuits
The first lawsuits have begun to roll in, targeting ERCOT and market participants for the non-rotating outages that left residents without power for at least 80 hours at a time.
In Houston, a trial lawyer filed a $100 million lawsuit against the ISO and Entergy Texas over the hypothermia death of an 11-year-old boy. Another lawsuit filed in Houston seeks $10 million from the grid operator and CenterPoint Energy for gross negligence. A third lawsuit filed in Corpus Christi asserts the grid operator and AEP Texas are responsible for property damage and business interruptions.
“We haven’t yet reviewed the lawsuits and will respond accordingly once we do. Our thoughts are with all Texans who have and are suffering due to this past week,” ERCOT said in a statement.
The legal efforts face long odds. ERCOT, a nonprofit government agency, enjoys sovereign immunity. The ISO has said it needs immunity from lawsuits because generators’ transaction fees fund the entity.
However, the Texas Supreme Court is expected to rule on a case later this year involving independent generator Panda Power and ERCOT that could eliminate that immunity.
FERC last week approved PJM’s proposed Operating Agreement language to provide more transparency in the conditions that exempt “immediate need” transmission projects from competition under Order 1000 (ER20-2686).
The commission first opened an investigation into PJM’s practices for designating immediate-need projects in October 2018, questioning whether it was opposing Order 1000’s competition mandate by misusing the exemption. (See FERC to Probe Order 1000 Competition Exemptions.)
Order 1000 allows a right of first refusal (ROFR) for transmission projects needed for reliability so urgently that there is insufficient time to hold a competitive proposal window.
The commission determined Thursday that PJM’s compliance filing “establishes a just and reasonable implementation structure for immediate-need reliability projects.” PJM had been ordered in June to make OA changes regarding language it developed to create a ROFR exemption. (See More Transparency Ordered on PJM ‘Immediate Need’ Tx.)
In its June order, FERC concluded PJM was complying with only two of the five criteria to limit the RTO’s discretion for applying the immediate-need exemption, saying it should be used only in “certain limited circumstances.”
Regarding the second criterion, FERC said PJM did not comply with a requirement that it separately identify and post an explanation of reliability violations and system conditions for which there is a time-sensitive need, including sufficient detail of the need and time sensitivity.
In Thursday’s filing, the commission determined that PJM’s proposed supplemental document providing details on each identified immediate-need reliability violation that the RTO proposes to exempt from the competitive proposal window process complied with requirements of the criterion. FERC also said PJM’s plan to both post the supplemental document on its website and include the supplemental document with Transmission Expansion Advisory Committee meeting materials met the criterion.
As an example of what the supplemental documentation would look like, PJM provided the compliance attachments for the Northern Neck Area and Manassas Area, two reliability violations the RTO identified as immediate need in 2020.
LS Power argued in a protest filing that the supplemental document should be part of “presentation” materials rather than “informational” materials. FERC said it was not persuaded by LS Power’s arguments and that it was satisfied with PJM’s solution.
“We expect PJM to adequately inform its stakeholders about all immediate-need reliability transmission projects such that transmission project-specific information will be included in the materials for TEAC meetings, included for discussion, and stakeholders will have opportunities to raise comments and questions about specific immediate-need reliability projects,” FERC said.
For the third criterion, FERC said PJM must provide a “full and supported written description” on any decision to award a project to an incumbent TO, including an explanation of other transmission or non-transmission options that the RTO considered and the cause of the need and why it was not identified earlier.
PJM proposed that the example attachments comply with the requirement to “provide a full and supported description of its decision to designate the immediate-need reliability project to the incumbent transmission owner, the alternatives considered and the circumstances generating the need, including why the need was not identified earlier.”
Protesters argued that the compliance attachments do not explain if other transmission and non-transmission alternatives were considered or why a time-sensitive reliability need was not identified earlier. LS Power also argued that the compliance attachments “make only sweeping statements about the reliability issues and the resulting determination that a competitive proposal window is infeasible.”
FERC said it agreed that PJM’s clarifications are “adequately responsive to these concerns” and that the compliance attachment for the Manassas Area specifically identified why a reliability need was not identified earlier. FERC did say PJM acknowledged that it “did not explicitly provide discussion of the alternative transmission and non-transmission options” considered in the attachment.
“In all future supplemental documents, we expect PJM to include an explicit explanation of other transmission or non-transmission options that it considered before designating an immediate-need reliability project,” FERC said.
Finally, in the fourth criterion, FERC said stakeholders must be permitted time to provide comments in response to the project description and the comments must be made publicly available. The commission had found that PJM providing three days for stakeholders to review immediate-need reliability project materials was not an adequate amount of time.
PJM proposed to revise the OA to add a specific period of “no less than 10 days” for stakeholders to review the meeting materials and transmission project-specific supplemental documents.
“We find that PJM’s proposed revisions are just and reasonable given the time-sensitivity of the reliability violations being addressed by proposed immediate need reliability projects,” FERC said.
The D.C. Circuit Court of Appeals on Friday upheld a FERC ruling that found a 2016 merger had left three ITC Holdings subsidiaries no longer fully independent, disqualifying them from a full return on equity incentive for standalone transmission providers.
The decision found there was “substantial evidence to support FERC’s finding that the merger had reduced ITC’s independence, thereby rendering the existing adders unjust and unreasonable” (International Transmission Company, et al. v. FERC, 19-1190).
FERC had granted International Transmission Co. and Michigan Electric Transmission Co. 100-basis-point adders in 2003 and 2005, respectively, and granted ITC Midwest a 50-point adder in 2015. But in October 2018 the commission found the companies were no longer fully independent because their parent company, ITC Holdings, had merged with Canadian and Singaporean companies (EL18-140).
ITC Midwest has been upgrading transmission in Iowa. | ITC
The commission affirmed its ruling in July 2019, saying the reduction in the adders was appropriate because the merger had reduced but not eliminated the companies’ independence. (See FERC Rebuffs ITC Call to Restore Full ROE Adders.)
The transmission companies appealed to the D.C. Circuit. They argued FERC had “arbitrarily and capriciously departed from precedent establishing a particular methodology to assess transco independence.” And they contended FERC had “exceeded its statutory authority by reducing ITC’s transco adders without first finding the adders to be unjust and unreasonable,” according to the court.
Regarding the first argument, a three-judge panel found it “fails at the outset because FERC, consistent with its stated intent in Order No. 679, never established any definitive methodology, let alone the one ITC claims it did.”
“FERC has consistently applied a case-by-case approach to determining transco independence, considering ownership and business structure as part of that inquiry since it first granted a transco adder in 2003,” the court said.
The companies’ claim that FERC had exceeded its statutory authority under Section 206 of the Federal Power Act also failed, the court found.
The law requires “FERC to show that an existing rate is unlawful before ordering a new rate,” and ITC argued that FERC had violated that mandate by failing to find the existing adders to be unjust or unreasonable before reducing them by half,” the judges wrote. FERC’s analysis, however, “clearly tracked the two-step procedure mandated by Section 206,” they said.
Nobody outside our industry understands our industry. And we see ourselves through a glass, darkly.
So with the tragedy in Texas (more specifically ERCOT, which is 90% of Texas’ load), there are plenty of politicians and talking heads spinning what happened and who or what is to blame. They’re mostly wrong.
There are two things not to blame. And two things to blame. Please let me explain.
Thing No. 1 not to Blame: Wind Generation
Yes, there is a lot of wind in ERCOT: around 30,000 MW. And yes, wind is intermittent.
That’s why ERCOT assumes that only a small fraction of maximum wind generation will be available when needed. The amount of available wind that ERCOT assumed this winter is 7,070 MW.[1] And ERCOT ran a sensitivity for low-wind output that assumed 5,279 of that 7,070 MW would not be available, leaving 1,791 MW available.
Now let’s look at what actually happened. This chart, “ERCOT Load vs. Actual Wind Output,”[2] shows that actual wind generation (the right vertical axis, in megawatts) during the Feb. 11-18 period had only two brief dips below the low-wind sensitivity of 1,791 MW.
ERCOT load vs. actual wind output Feb. 11-18 | ERCOT
So wind generation is a bit player in this tragedy.
Thing No. 2 not to Blame: Load Forecast
In the fall ERCOT forecasted an extreme weather winter peak load of 67,208 MW.[3] Now let’s look at the same chart showing ERCOT load during Feb. 11-18 (this time the left axis). The peak load was 69,222 MW, at 8 p.m. on Feb. 14.[4] This is only 2,000 MW more than the forecasted extreme weather peak load, and this forecasted peak was exceeded for only five hours.
Now to complete the picture, we need to recognize that early in the morning of the next day, Feb. 15, ERCOT began shedding load. So we would need to add back load shed in order to simulate unrestricted load. The load shed began at 10,500 MW at 1:25 a.m., and grew to 16,500 MW later that day.[5] If you look at the chart and envision the addition of the load shed, you’ll see that the unrestricted load does not exceed the peak at 8 p.m. on Feb. 14 of 69,222 MW.[6]
So the load forecast is also a bit player in this tragedy.
Thing No. 1 to Blame: Thermal Generation Maintenance Outages
Now we’ll discuss the real culprits: thermal generation (gas, coal and nuclear) or, more accurately, the lack thereof.
Two things went wrong with thermal generation: maintenance (planned) outages and forced (unplanned) outages.
Texas RE-ERCOT Seasonal Risk Scenario | NERC
To understand what happened with the first thing, please look at the chart “Seasonal Risk Scenario,”[7] which was prepared by the NERC in November 2020 from data provided by ERCOT. This is a “waterfall” chart starting with gross winter resources on the left side, and then making adjustments to arrive at expected net resources relative to extreme winter peak demand on the right side. As you can see, ERCOT forecasted an expected operating reserve of 2.3 GW under extreme conditions.[8]
If you look at the second bar from the left, ERCOT forecasted 4.1 GW of “typical maintenance outages.” Here’s the problem: ERCOT approved 14 GW of maintenance outages for this period,[9] about 10 GW more than it had forecasted.
This appears to be grid operator error.
Thing No. 2 to Blame: Thermal Generation Forced Outages
Now to thermal generation forced outages. Please look at the same chart, this time the third and fourth bars from the left. The third bar shows “typical forced outages” for thermal generation of 4.5 GW, and the fourth bar shows “derates” (outages) for “extreme conditions” for thermal generation of another 4.5 GW. The total is 9 GW, which is the forced outages for thermal generation under extreme conditions.[10]
Actual thermal generation forced outages: about 18 GW.[11] So actual forced outages were 9 GW more than ERCOT’s extreme conditions scenario.
To recap, there were 10 GW of excess maintenance outages and 9 GW of excess forced outages, for a total of 19 GW in unanticipated thermal outages, in line with the necessary load shed of 16.5 GW.
The Why
As I said earlier, the excess maintenance outages appear to be grid operator error.
But what about the excess forced outages? Extreme winter conditions regularly occur around the U.S. and the world without catastrophic loss of electric generation.
ERCOT has a market design that assumes that as long as wholesale prices are unlimited, supply and demand will always “clear” — basically equalize. New resources will be built and upgraded in anticipation of occasionally getting very high prices. And existing resources would incur new capital costs in order to receive those very high prices occasionally.
The problem has always been that the needed high prices occur rarely — like every 10 years — when they max out at $9,000/MWh, 360 times a typical wholesale price of $25/MWh. Who would finance and build needed resources and their winterization on such a GameStop bet? And when such prices do occur, the political, regulatory and market fallout can be staggering.[12]
Because of these real-world limitations, grid operators like PJM have adopted a hybrid market structure: a capacity market to assure that adequate resources will be available when needed, and an energy market that matches supply and demand on a least-cost basis every hour.
A capacity market spreads the needed compensation to maintain, build and secure adequate supply resources over every day, month and year instead of requiring speculation over a burst of revenue that happens maybe once every 10 years. And it penalizes any resource that does not perform when needed. The cost to customers is spread over time instead of unpredictable price surges maybe every 10 years.
It’s a form of insurance: You don’t need it until you need it.
“Perhaps most important, the state [Texas] does not have a ‘capacity market’ to ensure that there was extra power available for surging demand. Such systems elsewhere act as a sort of insurance policy so the lights will not go out, but it also means customers pay higher bills.”
Let me close by wishing the best to the good people of Texas, and the hope that we all learn the right lessons from this tragedy.
[8] Wood Mackenzie points out that ERCOT does not combine extreme conditions of high thermal outages and low wind when comparing to extreme winter peak load.
[9]https://www.woodmac.com/news/editorial/Breaking-down-the-texas-winter-blackouts/full-report/. Wood Mackenzie also reports that in the week before the storm hit, ERCOT tried to recall some of this generation but was not successful in doing so. Although Wood Mackenzie described all 14 GW as “offline for maintenance,” it is possible that some of that were forced outages, in which case that portion should be added to excess forced outages discussed in the next section. ERCOT apparently does not have the literal power to reject planned outage requests submitted more than 45 days in advance, but it is difficult to believe that a generator would insist on its timing if ERCOT advised that system reliability would be denigrated.
[10] Wood Mackenzie points out that ERCOT does not combine extreme thermal outages and the low-wind sensitivity when comparing to extreme winter peak load and that, if ERCOT had done so, it would have shown a negative operating reserve of 4 GW.
[11] Wood Mackenzie reports that total thermal outages the morning of Feb. 15 went from the 14 GW of maintenance outages to 32 GW, the difference being 18 GW of forced outages. A chart stacking forced outages on top of maintenance outages is in an article by Enverus here, https://www.enverus.com/blog/trading-and-risk/ercot-power-grid-outage-what-went-wrong/.
Eversource Energy and Vermont Electric Power Co. (VELCO) each presented replacement and refurbishment projects to the ISO-NE Planning Advisory Committee on Wednesday, with Eversource detailing its preferred solution to replace the only self-contained fluid-filled cable on its Connecticut transmission system.
Eversource’s Paul Melzen said the utility plans to remove 400 feet of the existing cable system and install 520 feet of solid dielectric cable in the duct bank at Branford 11J, a 115/23-kV substation located along the Connecticut shoreline. The project also calls for replacing two existing bus support structures and the relocation of an NRG Energy-owned 23-kV circuit from a combustion turbine housed in the substation to accommodate the route of the 115-kV duct bank.
The work’s estimated cost is $8.8 million, with a projected in-service date in the fourth quarter.
The fluid-filled cable was initially manufactured in 1981, and its creators are no longer in business. The cable has logged 26 work orders since 2005, including fluid leaks that increased maintenance burdens and reliability concerns. The continued decrease in oil pressure or oil level will eventually result in a trip of the cable. There was a service interruption in March 2017 that required complex restoration methods, according to Melzen. The cable is also located near a waterway, an environmental risk.
Eversource Energy wants to replace a self-contained, fluid-filled cable system with a solid dielectric cable system at a substation in Branford, Conn. | Eversource Energy
Melzen mentioned two potential alternatives to Eversource’s preferred solution. One is replacing the existing fluid-filled cable system with a new one, which would create the need for dielectric fluid accumulators, fluid-level pressure alarms, and additional maintenance and operational requirements. It would additionally pose an environmental threat with the release of dielectric fluid. There would also be limited equipment suppliers. The second is replacing the current cable system with an overhead bus, but there is a lack of real estate in and around the substation to accommodate it.
Hantz Presume of VELCO outlined three transmission line refurbishment projects at an estimated cost of $31.6 million, with the work completed between 2022 and 2024.
The most significant portion of the work will be along the 26.4-mile line from Essex to Middlesex, where 116 out of 305 wood H-frame structures with rotten pole tops and cross arms will be replaced with mostly steel H-frames to reduce VELCO’s current wood pole inventory. The line location is primarily mountainous, with difficult access and a challenging sloped right of way. The estimated cost is $15.2 million for the project, which is expected to be completed in 2024.
The other two projects are similar refurbishments along lines between Essex and Sandbar (11.2 miles) and West Rutland to Blissville (11.6 miles) that are expected to cost a combined $16.4 million and replace a total of 123 wooden frames with steel by 2022. Both lines have seen rotten crossarms and pole tops, and moderate to severe woodpecker damage.
Additional Items
ISO-NE Director of Transmission Planning Brett Oberlin gave a forward-looking presentation on dynamic reactive power devices. The RTO would like to use synchronous condensers as the preferred device to address system concerns identified in needs assessments, except under specific system limitations. Oberlin asked for stakeholder feedback by March 4.
Steven Judd, principal engineer in system planning for ISO-NE, provided stakeholders a summary of DNV GL’s stochastic time series analysis of variable energy resources (VERs). The RTO initially hired DNV GL in 2019 to use its weather modeling software and develop a historical dataset of all existing wind plants and future offshore wind plants from 2012 to 2018. It now contains hourly time series data for VERs, load and weather data in New England for 20 years (2000-2019). DNV GL also developed the Stochastic Engine, which can resample wind speed, irradiance, price and load into parallel and plausible scenarios. The weather-to-generation models simulate each weather scenario’s expected power production, creating thousands of 20-year simulations of hourly weather and power outputs.
