Texas utility Vistra said Wednesday it is taking on the “changing power generation landscape” as it announced earnings that were above management’s expectations.
Vistra reported third-quarter adjusted EBITDA from ongoing operations of $1.19 billion, a 10.3% increase from last year’s third quarter. Year to date, the company’s adjusted EBITDA is at $2.96 billion, up from 2019’s third quarter of $2.62 billion.
Since 2016, “we have meaningfully reduced our cost structure, strengthened the balance sheet to position the business to achieve investment grade credit ratings and enhanced the integrated model,” CEO Curt Morgan said in a statement. “We are now set-up to reinvest in our business as we transform our generation fleet for a sustainable future.”
In September, Vistra told investors it was developing nearly 1,000 MW of renewable generation projects in Texas, including six solar facilities and one battery, and intends to retire an incremental 6.8 GW of coal-fired generation in Illinois and Ohio.
Morgan reminded analysts that “every reputable and objective study” of electric generation sees natural gas playing a “significant role for several years to come, especially as we electrify the economy.”
“We believe we are a natural owner of renewable and energy storage assets given our capabilities and competitive position,” he said. “We have a high degree of competence that we can generate healthy return from these assets through the same skills and methodology by which we extract significant value from our existing fleet.”
Vistra’s strategy to transform itself into a leading renewables provider | Vistra
The Irving-based company said it expects to allocate about $1.15 billion of capital to transformational growth investments over the next two years, including its Moss Landing and Oakland battery storage projects in California. In May, Vistra entered into a 10-year resource adequacy agreement with Pacific Gas and Electric for a new 100-MW/400-MWh battery to complement the 300-MW/1,200-MWh battery already under construction at Moss Landing.
Vistra also said it had acquired the 60,000 Texas customers of Infinite Energy and Veteran Energy. That expands the footprint of TXU Energy, already the largest competitive retailer in in the Texas market.
The company uses adjusted EBITDA as a measure of performance because it says that analysis of its business is improved by visibility to both that metric and net income prepared in accordance with generally accepted accounting principles.
Vistra share prices peaked at $18.82 shortly after the market’s opening but finished at $18.34, down 5 cents.
FERC has accepted proposed revisions to seven NERC reliability standards submitted earlier this year under Project 2017-07 (Standards alignment with registration) (RD20-4).
The commission on Monday also approved the 2021 business plans and budgets for NERC, the regional entities and the Western Interconnection Regional Advisory Body (WIRAB) (RR20-6).
NERC began Project 2017-07 in order to update reliability standards affected by the risk-based registration (RBR) initiative approved by FERC in 2015 (RR15-4), which removed two functional categories — purchasing-selling entity and interchange authority — from the ERO’s compliance registry because “the commercial nature of these categories [posed] little or no risk to the reliability of the bulk power system.” The initiative also resulted in the creation of a new registration category, underfrequency load shedding (UFLS)-only distribution provider (DP).
Project 2017-07 was originally proposed in order to remove references to the discontinued categories and add UFLS-only DPs where needed to all families of NERC standards. However, during the course of the project, many of the standards were updated by other projects and removed from 2017-07’s scope. The final list of standards to be updated was approved by NERC’s Board of Trustees at its meeting in February. (See “Standards Actions,” NERC Board of Trustees Briefs: Feb. 6, 2020):
FAC-002-2 — Facility interconnection studies, replaced by FAC-002-3
IRO-010-2 — Reliability coordinator data specification and collection, replaced by IRO-010-3
MOD-031-2 — Demand and energy data, replaced by MOD-032-3
MOD-033-1 — Steady-state and dynamic system model validation, replaced by MOD-033-2
NUC-001-3 — Nuclear plant interface coordination, replaced by NUC-001-4
PRC-006-3 — Automatic underfrequency load shedding, replaced by PRC-006-4
TOP-003-3 — Operational reliability data, replaced by TOP-003-4
In its petition to FERC, NERC told the commission that changes were restricted to updating references to the affected organizations and that “no substantive revisions were made to the proposed reliability standards’ underlying requirements.”
Budgets Continue Focus on Cost Control
The ERO Enterprise business plans and budgets approved by FERC reflect NERC’s decision earlier this year to keep spending and assessments flat in light of the economic uncertainty arising from the COVID-19 pandemic. In its final budget released in August, NERC set its proposed 2021 budget at $82.9 million, up $203,000 from 2020. (See NERC Aims for Cost Control in 2021 Budget.) The total ERO Enterprise budget for 2021, including the REs and WIRAB, was projected at $211.2 million.
The final budget keeps to this target by, among other things, holding its 2021 staffing level to 213.38 full-time-equivalent employees, the same level as 2020. Personnel costs are expected to rise overall to $48.2 million, however, because of rising salaries and medical insurance premiums. Operating expenses are also up because of increased software support expenses for products such as the ERO Secure Evidence Locker.
NERC 2021 budget by program area | NERC
These rises were offset by savings in such areas as meetings and travel, down 33.7% at $2.2 million because of continuing pandemic-related travel restrictions, and fixed assets, down 29.5% to $3.3 million. Spending on the Electricity Information Sharing and Analysis Center (E-ISAC) is expected to drop by 4.8% as well stemming from the “re-evaluation of the E-ISAC strategic plan and optimization of current resources.”
In its budget filing, NERC also disclosed $1 million in penalties that it received between July 1, 2019, and June 30, 2020. The organization requested FERC allow it to deposit the funds in its assessment stabilization reserve, which the commission granted. Following the deposit NERC’s reserve will stand at $2.5 million.
Despite the short-term focus on cost savings, NERC has warned that budget hikes are likely as pandemic restrictions are loosened and the industry resumes normal business. (See NERC: Post-COVID Budget Rises Likely.) Earlier this year, the organization predicted budgets of $87 million and $91.4 million for 2022 and 2023, respectively.
FirstEnergy’s positive third-quarter financial results were overshadowed Monday by questions over the firing of CEO Charles Jones and the ongoing federal investigation into the company’s involvement in the $61 million bribery scandal over the passage of Ohio House Bill 6.
Christopher Pappas, FirstEnergy board member and new executive director, said the Department of Justice investigation into the bribery scheme has triggered several shareholder and customer lawsuits, and the company is responding to a U.S. Securities and Exchange Commission subpoena received on Sept. 2. Pappas said FirstEnergy is cooperating with both agencies.
In July, federal prosecutors alleged FirstEnergy spent $61 million in bribes, “dark money” campaign contributions and advertising to elect former Ohio House Speaker Larry Householder (R) and his allies in return for their support of HB6, which provided $1.5 billion in subsidies for the utility’s struggling nuclear plants. (See Feds: FE Paid $61 M in Bribes to Win Nuke Subsidy)
On Oct. 29, following an internal investigation related to “government investigations,” the company said it had fired Jones and two other officials, Dennis Chack, senior vice president of product development, marketing and branding, and Michael Dowling, senior vice president of external affairs, for violating its code of conduct. The firings came on the same day as the filing of guilty pleas of former FirstEnergy Solutions (FES) lobbyist Juan Cespedes and political strategist Jeffrey Longstreth, who admitted to participating in a racketeering conspiracy.
Steven Strah | First Energy
Steven Strah, president of FirstEnergy, was later appointed as acting CEO, while Pappas was named executive director. (See FirstEnergy Fires Jones over Bribe Probe.)
Pappas was asked Monday if other FirstEnergy officers or employees were in violation of the company’s policies or code of conduct. Pappas said he couldn’t comment as an investigation is still being conducted. “The investigation is still ongoing, and it would be premature to make any comments on that until we get to a more conclusive state,” Pappas said.
SEC Filing
While FirstEnergy officials were reluctant to answer further questions about the inquiry, an SEC filing by the company on Monday gave hints as to some of the behind-the-scene actions by investigators.
In the filing, FirstEnergy said it has received requests for information related to the government investigations, and those investigations and related litigation “could have a material adverse effect on our reputation, business, financial condition, results of operations, liquidity or cash flows.”
FirstEnergy confirmed that on July 21, it received subpoenas for records from the U.S. Attorney’s Office for the Southern District of Ohio requesting information related to HB6, Householder and other individuals associated with the former speaker. On Aug. 10, the SEC issued an order directing an investigation of possible securities laws violations by FirstEnergy, and on Sept. 1 it issued subpoenas to the company and “certain of its officers.”
The SEC filing said investigations and related litigation could divert the focus of FirstEnergy’s management and result in “substantial investigation expenses” and the commitment of corporate resources.
“We are unable to predict the outcome, duration, scope, result or related costs of the investigations and related litigation, or adverse impacts on federal or state regulatory matters, including with respect to rates, and, therefore, any of these risks could impact us significantly beyond expectations,” the SEC filing said. “Moreover, we are unable to predict the potential for any additional investigations, litigation or regulatory actions, any of which could exacerbate these risks or expose us to potential criminal or civil liabilities, sanctions or other remedial measures, and could have a material adverse effect on our reputation, business, financial condition, results of operations, liquidity or cash flows.”
Earnings and Company Moves
FirstEnergy reported earnings of $454 million ($0.84/share) on revenue of $3 billion, compared to $391 million ($0.73/share) on revenue of $2.9 billion for the same period last year. The results beat FirstEnergy’s internal expectations by a cent, company officials said, and it reaffirmed its outlook for the remainder of its fiscal year as well as long-term growth projections.
FirstEnergy’s Akron, Ohio, headquarters
Shares of FirstEnergy were up 19 cents, or 0.64%, to $30.12 as of closing on Tuesday.
FirstEnergy also announced it filed an application with FERC last week to move transmission assets in the Allegheny Power System zone to forward-looking formula rates. The move includes transmission assets in West Penn Power’s territory in Pennsylvania, Mon Power in West Virginia and Potomac Edison in West Virginia, Maryland and Virginia. FirstEnergy requested an effective date of Jan. 1.
It also created a new stand-alone transmission company, the Keystone Appalachian Transmission Co., to allow for new construction in the same footprint. FirstEnergy said last week it filed to establish a forward-looking formula transmission rate for the new company, and it plans on transferring certain transmission assets from West Penn Power and Potomac Edison by the start of 2022.
Company officials said they are currently taking steps to improve its liquidity and have been reaching out to its key stakeholders, including ratings agencies, banks, regulators, legislators and union leadership in the aftermath of the investigation.
The board has formed a new subcommittee of its audit committee to assess and implement potential changes to its compliance program. Leslie Turner, a FirstEnergy board member and former senior vice president of The Hershey Co., will lead the effort. Company officials said the new subcommittee will work with management, create an internal audit and engage outside expertise for help and best practices.
“I agree that the actions taken by our board of directors last week were absolutely necessary and are an additional step towards addressing this matter,” Strah said. “The management team is committed to working with the board to assess and implement potential changes as appropriate with the company’s compliance program. We take this as a serious and important matter, and we will begin to address this immediately.”
Federal officials are seeking input on a revised plan to use Western federal lands to create a network of energy infrastructure pathways that would likely provide a big boost to renewable project development.
The West-wide Energy Corridor — really a series of corridors — would wind through seven states, including California, Idaho, Montana, Nevada, Oregon, Washington and Wyoming.
The U.S. Bureau of Land Management, Forest Service and Department of Energy introduced the proposal in September 2005 under the authority of Section 368 of the Energy Policy Act of 2005.
The proposed West-wide Energy Corridor would run through seven Western states and increase the potential for developing new renewable projects. | BLM, USFS, DOE
Section 368 directs federal agencies to designate lands in the 11 Western states as right-of-way corridors for electricity transmission and distribution facilities, as well as oil, gas and hydrogen pipelines. It also requires the agencies designating corridors to take into account the “need for upgraded and new electricity transmission and distribution facilities” to “improve reliability,” “relieve congestion” and “enhance the capability of the national grid to deliver electricity.”
In 2009, the agencies prepared a programmatic environmental impact statement (PEIS), and BLM and USFS signed records of decision (RODs) designating about 5,000 miles of Section 368 energy corridors on BLM-administered lands and approximately 1,000 miles on USFS-administered lands.
But the effort to move ahead was stymied in July of that year when several conservation groups — including the Sierra Club and Natural Resources Defense Council — filed suit in federal court alleging that the PEIS and RODs violated the EPAct, National Environmental Policy Act, Endangered Species Act, Federal Land Policy and Management Act and Administrative Procedure Act.
In July 2012, the federal agencies signed a settlement with the plaintiffs that required the agencies to conduct regional reviews of Section 368 corridors and outline a handful of siting principles to guide those reviews.
Those principles require that the corridors must be “thoughtfully sited to provide maximum utility and minimum impact on the environment” and encourage “efficient use of the landscape for necessary development.” The agencies must also define “appropriate and acceptable uses” for specific corridors.
The revised plan contains numerous proposals to shift corridors to alleviate impacts on the environment and Native American reservation lands. It also proposes to eliminate a handful of corridors while adding two new ones in Wyoming and one each in Idaho and Oregon.
New Paths for Renewables
Most significant for renewable developers is a settlement stipulation that requires corridors to “provide connectivity to renewable energy generation to the maximum extent possible while also considering other sources of generation, in order to balance the renewable sources and to ensure the safety and reliability of electricity transmission.”
The revised plan, released Monday, points out that most of the 59 corridors identified in the 2009 West-wide plan already contained existing energy transmission infrastructure that was largely constructed to transmit electricity produced by fossil fuel, nuclear and hydroelectric generating facilities. Since then, the report notes, additional energy infrastructure has been built in those corridors, and many now have pending right-of-way applications for utility-scale renewable resources.
“Renewable energy development in Section 368 energy corridors is critical for connecting renewable energy sources to the grid,” the agencies said.
To bring that point home, the agencies cite the growing need for renewable energy in the West, particularly in California, combined with the remote locations of the regions with some of the greatest potential to generate that energy.
The proposal points to the large number of untapped designated solar energy zones (SEZs) on BLM land near Corridor 18-224 in Nevada.
“There is also a strong interest in solar energy development, combined with substantial existing geothermal energy production in this area. However, a lack of transmission lines to transport solar or geothermal energy to load centers presents a barrier for potential developers,” the plan states.
An isolated area of southeastern Oregon near Wagontire Mountain, positioned close to three Section 368 corridors, contains “significant” wind, geothermal and solar energy potential, according to the report.
“However, renewable energy resources require an additional north-south pathway east of Corridor 7-11 into California. A corridor addition in the area could serve to connect renewable energy to demand,” the plan states.
Wyoming currently has nearly 1,500 MW of installed wind capacity, with another 3,000 MW under construction, the reports notes. While the Gateway West project, slated for completion in 2024, will carry some of that generation to the West Coast, “additional infrastructure may be needed to transmit wind energy from Wyoming to out-of-state load centers, and Section 368 energy corridors could be well placed to accommodate that need,” the agencies contend.
The federal agencies are seeking comments on the revised plan by Jan. 31, 2021.
Nine conservation groups sued EPA on Monday over the agency’s move to weaken standards on water pollution emanating from coal-fired power plants.
The lawsuit, filed in the D.C. Circuit Court of Appeals, challenges EPA’s decision, issued last month, to alter the 2015 Effluent Limitations Guidelines (ELG), which require plants to use modern, affordable wastewater treatment technologies widely used in other industries.
It allows plants more time to reduce their wastewater pollution, extending the deadline for compliance by two years to the end of 2025. Plants can also use cheaper pollution-control technologies to remove toxic chemicals and heavy metals from wastewater if they are scheduled to retire by 2028. The agency’s revisions are expected to save utilities about $140 million each year.
The coal-fired Pleasants Power Station in West Virginia
“This absurd step backward is little more than a gift to the dirty fossil fuels industry at the expense of people’s health, endangered wildlife and water quality,” Hannah Connor, an attorney with the Center for Biological Diversity, said in a statement. “Many power plants could easily adopt affordable technologies that dramatically reduce toxic discharges, but with this rule, the EPA is telling their polluter friends not to bother with these common-sense measures.”
Joining the Connor’s group in the lawsuit are Chesapeake Climate Action Network, Clean Water Action, Environmental Integrity Project, Natural Resources Defense Council, PennEnvironment, Prairie Rivers Network, Sierra Club and Waterkeeper Alliance.
“This administration’s dangerous decision to give coal power industry lobbyists what they want will not stand without a fight,” said Earthjustice’s Thomas Cmar, one of the attorneys who filed the suit on behalf of the groups. “We’re working with our partners to stop hundreds of thousands of pounds of pollutants from contaminating sources of drinking water, lakes, rivers and streams each year.”
In response to an emailed request for comment, an EPA spokesperson told RTO Insider that the agency does not comment on pending litigation.
Although the coronavirus pandemic has sucked up most of the oxygen in this year’s presidential and congressional races, West Coast wildfires, record-breaking heat waves and more than two dozen tropical storms have also made climate change an issue impossible for voters to ignore.
A victory by former Vice President Joe Biden and a Democratic pickup of three Senate seats would reassert the U.S.’ commitment to the Paris Agreement on climate change and give the party a shot at enacting legislation to meet the agreement’s targets. President Trump’s re-election — even if he faces a hostile Senate — would likely mean four more years of climate denialism and regulatory rollbacks. The Washington Post reported last week that Trump had “weakened or wiped out more than 125 rules and policies aimed at protecting the nation’s air, water and land, with 40 more rollbacks underway.”
Regardless of what happens in D.C., however, state officials are likely to continue pursuing their own clean energy targets. In addition to races in 86 of the 99 state legislative chambers and 11 gubernatorial contests, state regulators are facing re-election from Georgia to Montana, with a climate-related measure on the ballot in Nevada.
Biden Plan
In July, Biden outlined a $2 trillion plan to eliminate power sector carbon emissions by 2035 and make the U.S. the leader in electric vehicle production, calling the climate change challenge a “once-in-a-lifetime opportunity to jolt new life into our economy, strengthen our global leadership [and] protect our planet for future generations.” (See Biden Offers $2 Trillion Climate Plan.)
Biden pledged to build on the billions in clean energy investments of the Obama administration and reverse the Trump administration’s environmental rollbacks. The Democratic candidate’s proposal was developed with input from former presidential candidates Sen. Bernie Sanders (I-Vt.) and Gov. Jay Inslee (D-Wash.) and is markedly more ambitious than the policies he backed during the primaries, when he called for spending $1.7 trillion over 10 years and eliminating CO2 emissions from power plants by 2050.
The shift reflects both his desire to motivate the liberal wing of the Democratic Party and to provide an economic stimulus to aid recovery from the pandemic. “We’re not just going to tinker around the edges,” he promised. “Science tells us we have nine years [to cut emissions] before the damage is irreversible, so my timetable [for] results is my first four years as president.”
The plan proposes funding to support EVs, improve energy efficiency and reduce the costs of clean energy technologies. Seeking to head off criticism that the plan will harm the economy, Biden framed his proposal as an economic development program, repeatedly referring to creation of “union” jobs.
Fracking an Issue in Pa.
During repeated campaign visits to the crucial state of Pennsylvania, Trump has warned that the former vice president will seek to eliminate fracking. Biden has denied the claim, saying only that he will end subsidies for fossil fuels and stop issuing new drilling permits on federal lands and waters.
ClearView Energy Partners calculated that the 10 counties responsible for 91% of Pennsylvania’s natural gas production had a significant role in Trump’s narrow 2016 win in the state. Except for Allegheny County, home to Pittsburgh, all of the top gas-producing counties voted for Trump, who added almost 31,000 votes to the total that GOP candidate Mitt Romney received in 2012. Trump won the state by less than 45,000 votes out of more than 6 million cast, a difference of 0.72%. Pennsylvania holds 20 of the 270 Electoral College votes needed to win the presidency.
Congress
Democrats are expected to hold or increase their current 232-197 edge in the House of Representatives. (There are also five vacancies and one Libertarian.) But approving legislation to implement Biden’s plans would likely require them to take control of the Senate, now held by Republicans 53-47, including two independents who caucus with the Democrats.
Polling indicates the Democrats will likely lose a seat in Alabama but gain one each in Colorado and Arizona. Democratic candidates also are within reach in toss-up races in Maine, North Carolina, Iowa, Georgia, South Carolina and Montana. A blue wave could also threaten Republican seats in Kansas, Texas, Alaska and Georgia’s second seat.
The commission is currently controlled 2-1 by Republicans. In July, Trump nominated Democrat Allison Clements, energy policy adviser for the Energy Foundation, and Republican Mark Christie, chair of the Virginia State Corporation Commission, to fill the two vacancies. (See FERC Nominees Bob and Weave Through Senate Hearing.)
Arizona Corporation Commission
In the West, Nevada voters will decide whether to require half the state’s electricity to come from clean energy resources by 2030, and voters in Arizona, Montana and New Mexico will vote for utility regulators in contentious races that could determine their states’ energy futures.
Renewable energy policy, via regulator elections and voter initiatives, is on the ballots of Western states Tuesday. | Bureau of Land Management
Three of the seats on the five-member Arizona Corporation Commission are up for grabs Tuesday, with only one incumbent on the ballot.
The commission, which regulates utilities and rates, voted Thursday to make the state the latest in the West to follow California’s lead and adopt a 100% clean energy mandate by mid-century. New Mexico and Washington have similar mandates approved by lawmakers.
The commission, which has four Republicans and one Democrat, voted 3-2. Chairman Bob Burns and Commissioner Boyd Dunn, neither of whom is seeking re-election, voted with Democrat Sandra Kennedy in support of the measure.
“The climate crisis is impacting Arizonans right now,” Kennedy said in a statement after the vote. “I am glad the commission was finally able to look past partisan politics to support science and economics-based policy that stakeholders, utilities and ratepayers could all agree upon and benefit from.”
The question of renewable energy and California’s influence on the more conservative Arizona has been a major source of contention in state politics and the utility industry.
Arizonans voted overwhelmingly in 2018 to reject Proposition 127, a measure that would have required the state’s power providers to generate at least half their annual sales of electricity from renewable resources by 2030. The race became a high-priced battle between California billionaire Tom Steyer, whose environmental advocacy group NextGen America backed the proposal, and Arizona Public Service (APS), which spent more than $50 million in the fight. (See High Failure Rate for Western Ballot Measures.)
Critics say APS has too much influence on commissioners, including through campaign contributions.
Six candidates are seeking the seats held by Burns, Dunn and Republican Lea Marquez Peterson — the only incumbent on the ballot.
The Washington Post reported Friday that billionaire and former New York City Mayor Michael Bloomberg, an advocate of carbon-free energy, had contributed $6.3 million to the three Democrats running: William “Bill” Mundell, Shea Stanfield and Anna Tovar. Two Republicans, Jim O’Connor and Eric Sloan, are also on the ballot.
The three leading vote-getters will join Kennedy and Justin Olson on the commission.
Arizona is one of 11 states where utility regulators are elected, not appointed by a governor or lawmakers. Also facing elections Tuesday, according to Ballotpedia, are regulatory commissioners in Alabama, Georgia, Louisiana, Montana, Nebraska, New Mexico, North Dakota, Oklahoma and South Dakota. (The 11th, Mississippi, elects its state officials in odd-numbered years, always in the year preceding the presidential election.)
The Montana race features Democrats running for two open seats on the all-Republican Public Service Commission, which has been plagued by infighting and scandal in recent years, the Montana Free Press reported. The commission’s support of coal power is out of sync with the growing progressive populations of cities such as Missoula and Bozeman, making change in the commission’s makeup and state energy policies a possibility this year.
New Mexico PRC
In New Mexico, lawmakers placed a constitutional amendment on the ballot that would shake up the state’s Public Regulation Commission by letting the governor appoint three at-large members in place of the five members now elected by geographic district. Both Republican and Democratic lawmakers overwhelmingly backed the ballot measure, and Gov. Michelle Lujan Grisham (D) supports it.
Many elected officials were angry with PRC commissioners for what they called an attempt to skirt the state’s landmark 2019 Energy Transition Act, signed by Lujan Grisham, which requires the state’s investor-owned utilities to get all their electricity from carbon-free sources by 2045. (See New Mexico Moves Toward Clean Energy, EIM Participation.)
Two current members of the PRC — Cynthia Hall and Stephen Fischmann — back the amendment, saying some of those elected to the PRC lack the backgrounds needed to understand complex regulatory issues.
Other members of the PRC argue that allowing the governor to appoint its members would deprive voters, especially those in rural disadvantaged communities, of the opportunity to influence ratemaking and policy decisions. (See Energy Amendments on NM, Nevada Ballots.)
Nevada Question 6
Nevada’s Question 6 asks voters for the second time in two years whether the state should make clean energy goals a part of its constitution.
A law signed by Gov. Steve Sisolak (D) in April 2019 requires the state to get half its electricity from non-carbon-emitting resources by 2030, but environmentalists worry it could be overturned by elected officials if the political winds shift.
Amendments to Nevada’s constitution must be approved in two consecutive elections, so the question faces a final vote this year after winning 59% support in 2018. That effort, like the current one, was bankrolled by Steyer.
The U.S. transmission system will require significant restructuring and greater alignment with public policy goals to meet the future needs of the electricity sector, according to industry insiders speaking at WIRES’ virtual fall member meeting last week.
The trade group promotes investment in transmission and progressive government policies to advance energy markets, economic efficiency, and consumer and environmental benefits through electric infrastructure development.
Here is some of what RTO Insider heard at the event.
Logjams, Dysfunction
During a panel on the integration of renewable energy and its impact on transmission, former FERC Chairman Joseph Kelliher said if he were an all-powerful king or wizard with a magic wand, he would change the structure of transmission ownership in the U.S.
Clockwise from top left: Joseph Kelliher, former FERC chairman; Rob Gramlich, Grid Strategies; Jasmin Melvin, S&P Global Platts; and Antoine Lucas, SPP | WIRES
“When I was at FERC, I was really stunned when National Grid testified at a FERC conference saying that the U.S. had at the time 492 different owners of the grid, and the government owns a third of the grid,” Kelliher said. “I think it would work better if you had a series of regional, national grids, something along the lines of our U.S. pipeline network. Pipelines are all corporate structured. They’re separated from production, dedicated completely to the business of moving other people’s gas. If you had regional, national grids whose only businesses were transmitting other people’s electricity, I think they’d be much more focused on quickly investing and anticipating the needs of the market.”
Kelliher added that the more realistic option is “effective, proactive regional transmission planning and execution of those plans.”
Grid Strategies President Rob Gramlich concurred and added that he does “a lot of work with renewable energy companies and associations, and what they see and feel right now is a symptom of a bigger disease.”
“What they see is interconnection queue logjams and dysfunction where you get to a certain number of projects in the queue, and suddenly the costs balloon, and then they jump out, and everybody else has to be restarted. It’s a total mess,” Gramlich said.
He said the interconnection queue problems could be “alleviated” by aligning transmission planning — and the cost allocation associated with it — with utility and state public policy goals.
Antoine Lucas, vice president of engineering for SPP, said he advocates for improved or increased alignment between the transmission planning processes and cost allocation.
“Any efforts that can create more alignment in that area, create more of a clear vision, will remove a lot of the hurdles that we see plague some of the transmission planning processes, including the generator interconnection process that Rob mentioned,” Lucas said. “We do have a lot of entities who are all working hard to try and serve the needs of their members or customers, but when you have so many different plans, different strategies, optimizing those is a significant challenge that if we could bring more alignment to it, I think we’d be able to see more get done at the national level.”
Kelliher said regional grid development currently relies “very heavily on network upgrades funded by generators,” which “is an inefficient way to build out the grid.”
“If you rely less on network upgrades and have more proactive regional planning, you have more clear cost allocation that’s as regional as possible,” Kelliher said. “You probably need to abandon the competitive provisions of [FERC] Order 1000, which I don’t take lightly. But I think the reason you have utilities deferring, going to great lengths to avoid regional cost allocation, is they don’t want competition for their projects.”
Gramlich said he would like to see much more hands-on leadership from FERC, “not just serving as sort of judges.” He cited current Commissioner Richard Glick and former Commissioner Cheryl LaFleur, now on the Board of Directors for ISO-NE, as positive examples of FERC working with governors and stakeholders on the interregional planning process.
Gramlich added there are “30 GW of offshore wind in the goals across the Northeast states [and] that it’s going to be much more efficient to proactively build transmission if those states get together and say, ‘OK, here’s what we’d like our RTOs and ISOs to do to proactively plan this.’ So, I think it will require both state and federal leadership outside of just the stakeholder processes.”
From the RTO perspective, interregional projects have two main challenges, Lucas said: cost allocation and siting. He said siting “seems to be an issue that creates a tremendous amount of friction, specifically when you’re talking about state authority versus federal authority.”
“I think any clarity on that would go a long way in helping to solve the problem, but I do recognize it’s a very challenging issue,” Lucas said. “If it were to be taken up again at FERC, I don’t know how successful it might be.”
‘No Silver Bullet’ for Energy Transition
In his keynote speech, Sen. Joe Manchin (D-W.Va.), ranking member on the Senate Energy and Natural Resources Committee, said the demand for clean energy is growing to address climate change. The challenge, however, is “maintaining affordable, reliable and dependable energy while also reducing emissions, and ensuring that hardworking families and communities that have powered our nation to greatness aren’t left behind in the transition.”
Sen. Joe Manchin (D-W.Va.) | WIRES
“There’s no silver bullet. We’re going to need a variety of solutions to ensure we can meet this challenge both at home and around the world, where fossil fuels are going to be used for decades to come,” Manchin said. “That’s why I say we need innovation, not elimination.”
Manchin said that his and Sen. Lisa Murkowski’s (R-Alaska) American Energy Innovation Act would invest $24 billion to advance critical technologies such as renewable energy, advanced nuclear, cybersecurity, energy storage, grid modernization, and carbon capture, removal, utilization and sequestration. It would also push technologies that can reduce emissions in four sectors of the economy that currently contribute about 90% of the nation’s overall greenhouse gas emissions.
“These varied solutions are necessary for us to reach any goal for reducing greenhouse gas emissions,” said Manchin, who hopes the bill comes to a vote during the lame-duck session following the elections. “They would also strengthen the United States’ position as an exporter of the technologies other countries will also need to tackle this global climate problem.”
Manchin added that the energy mix is changing with more renewables coming online and the retirements of older fossil-fuel units. That means “cost-effective energy storage is a critical technology to advance, and that’s also why a more flexible and modern electric grid is needed,” he said.
He said there is “a good argument for investment in grid infrastructure to help us meet our challenges.”
“We know that transmission is an essential component of a reliable and resilient grid because we know what happens when congestion disrupts the system,” Manchin said. “I expect transmission to get a good deal of attention next year. I know several bills seek to advance transmission by improving the interregional planning process at FERC or extending the investment tax credit to transmission.”
Manchin added that he hoped the “two very qualified nominees” for FERC — Allison Clements and Mark Christie — can be confirmed during the lame-duck session. (See FERC Nominees Bob and Weave Through Senate Hearing.) Clements, a Democrat and energy policy adviser for the Energy Foundation, and Christie, a Republican and chair of the Virginia State Corporation Commission, were nominated by President Trump in late July. Clements would fill the seat left open by the departure of LaFleur in August 2019. Christie would take the place of Bernard McNamee, who departed in September.
“I think we can all agree that the best FERC is a fully seated FERC,” Manchin said.
Xcel Energy on Thursday reported third-quarter earnings of $603 million ($1.14/share), beating Zacks Investment Research’s consensus expectation by 7 cents. A year ago, Xcel’s earnings were $527 million ($1.01/share).
The company narrowed its 2020 earnings guidance to $2.75 to $2.81/share and initiated its guidance for 2021 at $2.90 to $3/share.
The Minneapolis-based company said it intends to invest $22.6 billion in base capital, including an incremental $1.4 billion addressing COVID-19’s economic effects in Minnesota. Xcel has proposed spending money on the grid, solar facilities and repowering aging wind farms, which it said would create 5,000 jobs and add 5 GW to its renewable portfolio.
| Xcel Energy Center
Xcel also outlined a 10-year vision to power 1.5 million electric vehicles in its service territory by 2030. The company already installs home chargers for customers but wants to see fast-charging stations expanded along highways and other travel corridors.
“I’m particularly excited about EVs. … The variable cost of an EV is significantly below that of a gasoline[-fueled]” vehicle, CEO Ben Fowke told financial analysts, with the cost of EV charging equivalent to 60-cents/gallon gasoline. “So while EVs are expensive today, we think that cost comes down. The key to me is to get these stations built. … One of the biggest barriers to purchasing an EV is range anxiety.”
Xcel’s share price closed Friday at $70.03, having lost 23 cents after the earnings release.
ERCOT stakeholders last week approved the oldest protocol change on the grid operator’s books, shooting down a late request to table the measure in the process.
Luminant filed comments on the revision request the day before it would be considered by the Technical Advisory Committee and requested a delay so committee members could review the comments.
The Nodal Protocol revision request (NPRR945) is hardly controversial. It simply removes the “associated load” term that proponents say has been interpreted in some instances to restrict private-service arrangements otherwise authorized under state law and regulatory precedent.
“We filed the comments because we’ve heard from different groups that the NPRR didn’t change anything,” Luminant’s Ian Haley said during the TAC’s web meeting Wednesday. “We had concerns that TAC would be voting without understanding what it does. We wanted to ensure TAC is well aware of what we’re voting on today.”
Attorney Katie Coleman, representing Texas Industrial Energy Consumers and the measure’s sponsor, accused Luminant of “a little bit of sandbagging,” noting the revision dates back to May 2019 and that the company has had “ample opportunities to relay this concern.”
She reminded members that the issue has been discussed several times within the TAC’s Protocol Revision Subcommittee and that she conducted a workshop where she went through the NPRR’s effects and its history.
“This section of the protocols was meant to define the electric configurations that were eligible for net metering. It does not pertain to legal and regulatory requirements,” Coleman said. Referring to “associated load” as an “ambiguous term,” she said, “That term has been interpreted as load and generation to be owned by the same entity.
“That’s not what the language says, and I’m not sure it’s clear to market participants. It’s more restrictive than what the law allows in certain scenarios,” Coleman said. “We have [private-network] sites set up today, lawfully set up, and some reviewed by the [Public Utility Commission] in contested cases, where load and generation is not owned by same entity.”
Removing the term, Coleman said, will provide regulatory certainty for both existing and planned sites by deferring to legal and regulatory precedent and avoid potentially inconsistent interpretations of the protocols.
The NPRR adds language that “explicitly state[s]” that private-service arrangements must comply with PUC precedent and Texas’ Public Utility Regulatory Act. It also adds market transparency with a new reporting requirement that identifies all generation resources and settlement-only generators registered as part of behind-the-meter private-use networks (PUNs).
Luminant says NPRR945 provides clarity to those seeking to set up PUNs, but it raises “many additional and equally important policy questions, some of which cannot be addressed by ERCOT stakeholders.”
The generation company said PUNs are neither typical loads nor typical generation resources and are subject to nonmarket incentives that “warrant appropriate controls” to ensure their usage “balances risk and reward fairly across market sectors and customer classes.”
“In an energy-only market, this can actually harm resource adequacy objectives … by allowing a single entity to capture scarcity value that does not accrue to the rest of the market,” the company said in its comments. “Luminant supports correct pricing outcomes that utilize the demand of consumers in ERCOT and all generation bids needed to meet that demand. Unfortunately, [PUNs] bypass this needed aspect of price formation.”
“As Luminant is starting to understand, this has potential implications that are pretty serious,” said Golden Spread Electric Cooperative’s Michael Wise, saying he was concerned about cost shifts and their unintended consequences. “ERCOT’s interpretation of the protocols and the term ‘associated load’ has protected consumers very well. We believe it’s probably one of the most important issues brought forward to stakeholders and it merits this attention.”
Other TAC members weren’t so sure.
“With all due respect to Luminant and Golden Spread, these issues you’re raising are issues we’ve been discussing for months and months,” Demand Control’s Shannon McClendon said. “Katie has given detailed information. PUNs do not cause additional costs to the consumer. That’s a red herring Golden Spread is putting out there.”
Reliant Energy Retail Services’ Bill Barnes said that although he shared some of Luminant and Golden Spread’s concerns, he was “cautiously supportive” of NPRR945.
“I don’t think minds will change in one month. I don’t see the need to table,” he said.
The motion to table failed 8-22. The TAC then passed the measure by a 23-5 margin, with two members abstaining.
Staff, WMS to Address Market Delays
ERCOT staff will work with the TAC’s Wholesale Market Subcommittee to address what has literally become a growing problem.
At issue are the increased complexities of the day-ahead market (DAM), which has led to a steady increase in the market’s ability to publish its results on time. There have been 20 delays this year, the most since 42 in 2011, the first year of ERCOT’s nodal market.
ERCOT has seen increasing delays in its day-ahead market, driven in part by more granular point-to-point bids. | ERCOT
The grid operator allots three-and-a-half hours for the DAM’s execution, during which software must optimize its time, validate data inputs, execute the price-validation tool and post results, among other tasks. Input/output verifications and data errors can also lead to delays.
“There’s a lot of iteration in the DAM’s execution. Because of those iterations and other factors, we could have long run times to clear the DAM,” said Kenan Ögelman, ERCOT vice president of commercial operations. “If we get more than 170,000 [point-to-point (PTP) interval] submissions, we’ll pretty much have a DAM delay. An increase in settlement points can also lead to long run times.”
Ögelman said DAM participation has trended upward, with PTP bids largely contributing to the increased variables. Energy bids and energy-only bids have also grown, and binding constraints are on an upward path.
He said staff haven’t been “sitting on our hands,” but going after low-hanging fruit — “easy for us to do on our own,” Ögelman said — has resulted in staff falling further behind in solving the problem.
“We would like to engage stakeholders in an organized basis,” Ögelman said. “When I look at the solutions before us, they all have some drawbacks. I’m not seeing some perfect, low-cost solution without adverse effects.”
TAC Approves 7 Changes, Tables 8
The TAC’s unanimously approved consent agenda resulted in the approval of four NPRRs, a system change request and single revisions to the Planning Guide and Settlement Metering Operating Guide. Eight other change requests were tabled while they wait on their related NPRRs.
NPRR1028: requires qualified scheduling entities to notify ERCOT of physical limitations on their resources’ starting ability that are not modeled in the reliability unit commitment software and excuses compliance with parts of RUC dispatch instructions that violate a notified resource’s physical limitations. The NPRR also establishes a requirement that ERCOT extend a RUC commitment to honor a resource’s minimum run-time limitation when a physical limitation delays its ability to reach its low sustained limit.
NPRR1031: requires ERCOT to post operations messages informing market participants when load is curtailed because of a transmission problem.
NPRR1032: limits the DC tie schedules used in RUC optimization and settlements to the ties’ physical rating.
NPRR1041: adjusts the expiration of the protected information status of wholesale storage load data from 180 days to 60 days, aligning the disclosure of real power consumption and metered generation output to 60 days after each operating day.
PGRR023: adds a requirement that transmission service providers submit and annually review a list of contingencies for their portion of the system, ensuring that the appropriate contingencies are submitted for ERCOT and NERC planning criteria.
SCR812: creates an Intermittent Renewable Generation Integration report similar to wind and solar power production integration reports.
SMOGRR023: provides an option for a professional engineer’s nameplate certification of newly installed or replaced instrument transformers when nameplate photos cannot be physically accessed, and replaces a list of instrument transformer nameplate data requirements by referencing Institute of Electrical and Electronics Engineers standards.
Entergy held its third-quarter earnings call with financial analysts Wednesday as yet another hurricane, the fifth to hit Louisiana this season, bore down on the state.
“We’ve activated our storm response plan, and we are fully prepared and ready to respond,” Entergy CEO Leo Denault told analysts. “We’ve had a record-breaking storm season with back-to-back hurricanes hitting our service area. Yet no matter what 2020 threw at us, we remain steadfast in delivering on our commitments to our customers, our communities, our employees and our owners.”
Hurricane Zeta made landfall later that evening, ripping through Entergy’s New Orleans hometown with 110 mph winds. The most powerful hurricane to hit the U.S. this late in the year since 1899, Zeta knocked out power to more than 480,000 customers. By Friday morning, 327,000 were still without service, with some facing prospects of a full week without power.
Zeta followed Laura in August and Delta in October, both of which caused significant damage west of New Orleans. Aided by mutual assistance partners, Entergy deployed 12,000 workers after Delta to restore most of the nearly 500,000 outages in five days.
“We showed why we are best-in-class in storm response as we successfully managed to back-to-back major hurricanes all amid a global pandemic. That’s what we prepare for, and that’s what we do,” Denault said. “We can control what we can control. We can’t control the public health crisis, so we’re going to control what we can control.”
Entergy service trucks line up in preparation for restoration work. | Entergy
Entergy reported third-quarter earnings of $521 million ($2.59/share), as compared to 2019’s third quarter of $365 million ($1.82/share). That exceeded analysts’ expectations of $2.42/share, according to Zacks Information Research.
Denault said the results “amid these extraordinary times” demonstrated Entergy’s progress in building a “simpler, stronger and more resilient company.”
Entergy’s share price lost traction during the week, as did the rest of the broader market. Shares closed Friday at $101.22, down 5.8% following the earnings announcement.
Texas utility Vistra said Wednesday it is taking on the “changing power generation landscape” as it announced earnings that were above management’s expectations.
