The California Department of Forestry and Fire Protection said last week it found that a tree falling onto a PG&E distribution line last July ignited the nearly 963,000-acre Dixie Fire, the second largest in state history, which destroyed more than 1,300 structures and killed one person.
“The Dixie Fire investigative report has been forwarded to the Butte County District Attorney’s Office” for possible criminal prosecution, Cal Fire said in a Jan. 4 news release.
Butte County prosecutors won 85 felony convictions against PG&E for starting the devastating Camp Fire in November 2018, killing 84 residents, and now are leading a coalition of five counties investigating PG&E’s role in the Dixie Fire.
The finding that PG&E started the wildfire was not a surprise; PG&E said soon after the blaze began that its line may have ignited the blaze. (See PG&E Expects $1B in Costs from Dixie Fire.)
“As we shared in our public statement in Chico in July after the start of the Dixie Fire, a large tree struck one of our normally operating lines,” PG&E said in a statement following Cal Fire’s announcement on Jan. 4. “This tree was one of more than 8 million trees within strike distance to PG&E lines.”
“Taking a bold step forward, PG&E has committed to burying 10,000 miles of lines in addition to the mitigations included in PG&E’s 2021 Wildfire Mitigation Plan,” the utility said. “Regardless of today’s finding, we will continue to be tenacious in our efforts to stop fire ignitions from our equipment and to ensure that everyone and everything is always safe.”
Last year, prosecutors in Sonoma and Shasta counties charged PG&E in the 2019 Kincade Fire and the 2020 Zogg fire. Cal Fire determined a tree that fell on a PG&E line started the Zogg Fire. The cause of the Kincade Fire remains under investigation.
PG&E acknowledged its lines likely started both fires but denied it was criminally liable for either blaze.
In November, the independent monitor appointed by the court to oversee PG&E during its probation said the utility needs to make substantial improvements in its efforts to prevent wildfires through vegetation management and grid hardening.
“Multiple years of horrific wildfires” started by PG&E equipment showed “its progress regarding wildfire mitigation obviously has been inadequate, and we doubt anyone would seriously dispute that, given the ongoing and profound safety issues in that area of operations,” the law firm Kirkland & Ellis, which the court appointed monitor, wrote in its report to Alsup.
“Including the Camp Fire fatalities, over 110 people have died as a result of wildfires where Cal Fire has determined PG&E equipment was involved since the San Bruno incident,” which killed 8 people, the monitor wrote.
Its reviews of PG&E safety practices showed the utility probably has missed tens of thousands of dangerous trees near its lines and failed to detect worn or broken equipment in many situations. PG&E still has a vast backlog of problems to fix from a 2019 inspection of 685,000 distribution poles, 50,000 transmission structures and 200 substations in high-fire threat districts, the monitor noted.
“There are over 500,000 tags from 2019 to present that remain unresolved to date,” it said.
The monitor also expressed skepticism about PG&E’s plans to bury 10,000 miles of power lines in fire-prone areas. CEO Patti Poppe announced the effort in July during the same media event in which she discussed the utility’s possible role in starting the Dixie Fire. (See PG&E Proposes Undergrounding 10K Miles of Distribution.)
“The monitor team applauds PG&E’s commitment to undergrounding to mitigate wildfire risk but notes that some serious questions and issues remain regarding PG&E’s implementation of the undergrounding initiative,” it said.
The utility did not give a time frame for the work but has plans to underground just 66 miles of lines in this year and a total of 327 miles over the next three years, the monitor said.
Even if it greatly increases its efforts over a 20-year period, “there is substantial skepticism among PG&E field personnel that PG&E can feasibly underground more than 500 miles per year using current technology and hardening methodologies,” the monitor said.
Recent uncertainty over New Hampshire’s energy efficiency program continued last week, as the House of Representatives passed a bill to govern its pricing, while regulators dug in on their decision to roll back utilities’ recent budget proposal for the program.
State representatives Thursday unanimously passed House Bill 549, which would set the system benefits charge (SBC) at 52.8 cents/kWh, as approved for 2020, to fund New Hampshire’s 2021-23 Triennial Energy Efficiency Plan. The bill also would authorize the Public Utilities Commission to adjust the SBC annually based on inflation.
The measure is one of a series of steps stakeholders and legislators are taking following a PUC order Nov. 12 that basically reversed course on utilities’ three-year program proposal. (See NH EE Plan Approaches 2nd Year without Funding Certainty.) In its order (DE 20-092), the PUC said the proposed program budget of nearly $400 million was too high and directed the utilities to submit a new budget in line with the 2018-2020 plan.
While the House last week unanimously passed the bill to set program funding, it was only after Republicans and Democrats were split on a vote for the amendment that set the new SBC language. All but one Republican voted for the amendment, and all but two Democrats voted against it.
In both voting against the amendment and passing the final bill, Democrats were signaling that they support the basis of the bill but believe that it needs more work, Sam Evans-Brown, executive director of Clean Energy NH (CENH), told NetZero Insider.
The bill is “awful for New Hampshire citizens who are utility ratepayers,” Democratic Rep. Rebecca McWilliams said in a statement. “It moves SBC rate setting to the legislature, which means the rate will rarely (never) go up with inflation.”
Democrats are concerned that legislative control of the SBC will lead to an annual fight among policymakers over what the rate should be, Evans-Brown said. That means that any certainty the bill seeks to achieve might not be realized in the long term.
Republican Rep. Michael Vose, chair of the House Science, Technology and Energy Committee, believes the bill will put “guardrails” on the program’s funding. Under the utilities’ 2021-2023 plan, the SBC would have doubled, he said in a statement, adding that “the bill prevents that by striking a balance between investing in energy efficiency and protecting ratepayers from unsustainable increases to their electric bills.”
The bill now goes to the Senate, where McWilliams hopes it will be “further refined.”
For Evans-Brown, the bill will need to go beyond mere budget setting and “set the clock back” to before the PUC’s Nov. 12 order.
“The problem with the order is that it [shrunk the program budget] in such a way that it blew up all of our energy efficiency policies,” he said, adding that the order left the utilities wondering what they can do with the new budget.
Despite still needing to make its way through the legislative process and go to the governor for approval, passage of the bill could provide an expedient pathway to relief that stakeholders have yet to find elsewhere.
PUC Order on Rehearing
On Friday, the PUC denied requests for a rehearing of its order restructuring the three-year program.
New Hampshire’s utilities, the Consumer Advocate, advocacy groups and the New Hampshire Department of Energy filed rehearing requests in early December, primarily claiming that changes to the program administration in the order were “retroactive in nature” and departed from precedent.
The PUC disagreed with their arguments.
Conservation Law Foundation attorney Nick Krakoff said the organization “will continue the fight to overturn” the PUC’s “irresponsible” November order.
In a separate order on Friday, Commissioner Pradip Chattopadhyay denied a Dec. 17 motion by the Office of the Consumer Advocate (OCA) for his disqualification from the docket. The OCA claimed that Chattopadhyay’s prior work in the OCA was a conflict of interest. Chattopadhyay, however, said the OCA did not sufficiently demonstrate that he had any involvement in the docket before joining the commission.
CENH Lawsuit
A New Hampshire judge on Dec. 29 denied a request filed in Superior Court by a group of the state’s energy efficiency industry stakeholders, led by CENH, seeking a temporary injunction staying the PUC’s order.
The judge said the court lacked “subject matter jurisdiction to entertain appeals from PUC rulings, orders and rules,” and that the state’s Supreme Court has “exclusive jurisdiction” over the case.
Plaintiffs filed a motion to reconsider on Jan. 3, arguing the opposite and that there is no adequate remedy of law for immediate relief.
“One of the most disappointing pieces from the judge’s order … was the insistence that the New Hampshire Supreme Court … ‘can act with great alacrity when it needs to,’” Evans-Brown said.
Expediency, according to the petitioners, is imperative in this case to prevent layoffs that would stem from the PUC’s order, which they say effectively defunded ongoing activities of the state’s energy efficiency industry.
At this point, Evans-Brown said, CENH and other advocates are shifting their approach to find relief.
It’s not clear how a legal case would move ahead at this point, he said, but it is “100% certain” that stakeholders will appeal the PUC’s order to the Supreme Court.
“I think we are headed on a different path strategically, which is to say, instead of hoping that the Supreme Court will ride in on a white horse and get the contractors back to work, we are going to focus on a legislative solution in the near term,” he said. “In the long term, we hope that the New Hampshire Supreme Court understands the real problems with this order from a due process perspective and vacate it so that it does not become a precedent.”
Governor-elect Glenn Youngkin (R) shook Virginia’s environmental and clean energy advocates Jan. 5 with his controversial nomination of Andrew Wheeler, who led EPA under President Donald Trump, to be Virginia’s next secretary of natural resources.
But when Youngkin takes office Saturday, he will be leading a state widely recognized as a Southern leader in the U.S. energy transition, with strong targets for grid decarbonization under the Virginia Clean Economy Act (VCEA).
Further, with a slim Democratic majority holding the line in the state Senate, Youngkin and the Republican majority in the House of Delegates will not be able to repeal the VCEA or take Virginia out of the Regional Greenhouse Gas Initiative (RGGI), as the governor-elect has vowed to do. Democratic lawmakers have also declared they will fight Wheeler’s nomination “tooth and nail.” (See Youngkin Taps Trump’s Former EPA Chief to Head Virginia DNR.)
Even putting the partisan state of play aside, the momentum of cleantech in Virginia may be hard to slow down, as demonstrated by a series of plans and reports announced in the runup to Youngkin’s inauguration.
On Dec. 30, Appalachian Power filed its 2022 renewable energy plan, as required by the VCEA, with modest commitments to add 294 MW of solar and 204 MW of wind to the utility’s generation mix over the next three years.
And on Jan. 1, the outgoing administration filed its VCEA-mandated report on the least-cost strategies for grid decarbonization, including a finding that the low cost of clean energy will outweigh any need for the state legislature to prohibit new fossil fuel plants. Dominion Energy also started the new year with a Jan. 7 ruling from the State Corporation Commission (SCC) giving it the go-ahead for the second phase of its grid modernization program, which includes preparing the utility’s distribution system for high levels of distributed energy resources.
Solar Grows, but Coal Stays
Appalachian’s new solar and wind power procurements were the top-line items in the company’s Jan. 4 announcement of its 2022 VCEA plan. The utility will acquire a 204-MW wind farm in Illinois and a 150-MW solar plant in Virginia; it will also sign power purchase agreements for three additional solar projects, totaling 89 MW, according to the plan, which will need approval from the SCC.
The utility “intends to meet its VCEA targets primarily through investments in solar, wind, energy storage and purchase of market renewable energy certificates,” it said. “By 2040, the company expects to add approximately 3,300 MW of solar, 2,600 MW of energy storage and nearly 3,000 MW onshore wind to its current portfolio of wind and hydro resources.”
Building out its renewable portfolio will provide near-term savings, according to Ismael Martinez Jr., resource planning manager for the utility’s parent company, American Electric Power (NASDAQ:AEP). In the 2022 plan submitted to the SCC, Martinez said the new solar would “help Appalachian avoid costs it would otherwise incur as a PJM participant, especially by helping the company to avoid purchasing energy from the PJM energy markets, which can be volatile.”
Solar can also be used as a distribution resource, Martinez said, to “reduce the company’s load during the PJM … coincident peak hours, thus providing a capacity obligation benefit by allowing the company to avoid an incremental purchase of capacity in the future.”
But reaching these and other VCEA goals could be challenging. The most recent figures on Appalachian’s generation mix, from September 2021, show that close to 65% of its power comes from coal and another 19% from natural gas, according to a company spokesperson. Most of that coal-fired power comes from two plants in West Virginia, which the utility intends to keep online through 2040, eventually replacing their combined 4,235 MW with carbon-free power.
If fossil fuel generation were to be used to replace the coal plants, it would be located out of state, the plan says.
Appalachian looked at the possibility of closing the coal plants by 2028, according to the plan. But in August the West Virginia Public Service Commission ordered the utility to make improvements at the two plants to bring them into compliance with federal wastewater regulations, which will allow them to stay online past 2028. Who will pay for these improvements has become a flash point since the SCC rejected Appalachian’s request to recover part of the costs from its Virginia customers, while the PSC has said West Virginia consumers may have to foot the bill for the upgrades on their own.
Andy Farmer, interim director of the SCC’s Division of Information Resources, said the commission has yet to schedule any hearings on Appalachian’s plan.
“Commission staff is reviewing the application to ensure that it is complete, and in a few weeks the SCC will issue a procedural order that provides opportunities for public comment and a schedule for hearings,” Farmer said.
Least-cost Path to 100% Clean Power
The VCEA report — compiled by the Natural and Historic Resources Department and Commerce and Trade Department, and submitted to the legislature on Jan. 1 — looks at the least-cost strategies for Virginia to reach a decarbonized grid by 2045. That goal can be achieved with existing technologies based on the VCEA’s renewable energy and energy efficiency standards and the emission reductions possible through RGGI, the report says.
The law calls for the state to add 16,100 MW of solar and onshore wind, along with 3,100 MW of energy storage. The solar industry alone could add tens of thousands of jobs to the state’s workforce as the sector grows from $1.3 billion to $8.1 billion in economic activity over the coming decades, numbers that underline the “economic strength of the clean energy sector,” the report says.
Getting to 100% clean energy: By 2045, Virginia could still have some natural gas generation, but it will account for only a small amount of the terrawatt-hours of power solar, wind and other clean technologies will provide. | Resources for the Future and Virginia Energy
“The emerging/advanced/clean energy sector is already a significant share of the energy economy in the commonwealth and is only poised to grow — largely because of the VCEA and the policy certainty it provides,” the report says.
Perhaps with Youngkin in mind, the report also warns that “markets working to drive clean energy growth will be limited without policy to help drive that growth. Low-carbon energy technology is widely acknowledged as the cheapest source of new electricity capacity, but strong policy signals ensure that the market responds at a rate reflecting the pressing need to eliminate greenhouse gas emissions.”
Rolling back the VCEA “could send a negative signal to industries already investing in Virginia,” the report says, pointing to the state’s expanding offshore wind industry as a key example. The rapid development of the sector is being driven by the VCEA’s target of 5,200 MW of offshore projects by 2034.
At the same time, the report does not recommend that the legislature pass any laws prohibiting the permitting of new fossil fuel generation. Such resources will be needed in the near term for reliability and flexibility, and the clean energy and efficiency targets in the VCEA will provide a competitive advantage for solar, wind and storage, the report says.
It also anticipates that nuclear power, which currently generates just under a third of the state’s electricity, will continue to provide a significant portion of its power. Natural gas, while still in the mix in 2045, will have shifted from baseline to seasonal backup power. By 2040, the state will have retired all but 20% of its legacy fossil fuel plants, and almost all new generation will be solar, wind and storage, the report says.
DERs
With the SCC’s approval of the second phase of Dominion Energy’s (NYSE:D) grid modernization plan, the utility announced it will be investing $650 million this year and next for a range of distribution system improvements and upgrades, from the installation of 1.1 million smart meters to a management system for integrating DERs.
But the commission’s ruling also came with conditions that Dominion show the value of those investments. For example, the utility’s plans to spend $198.3 million on smart meters must also ensure the technology will be optimized to provide customer savings and demand-side flexibility. A time-of-use rate the utility has been piloting will be developed into a systemwide offering, along with the creation of an opt-in demand response program providing peak-time rebates.
Dominion’s request to spend $5.2 million on a DER management system drew opposition from commission staff, who argued that the utility’s distribution system can handle the relatively low levels of DERs now installed.
The company had also pitched for the investment as necessary to better leverage aggregated DERs for the PJM system in compliance with FERC Order 2222. Again, staff raised concerns, this time about the uncertainty surrounding the RTO’s compliance filing, and Dominion agreed to put a hold on system implementation until the filing is submitted and approved.
California Gov. Gavin Newsom on Monday released a fiscal year 2022/23 budget plan that proposes spending $22.5 billion over the next five years to fight climate change, including allocating billions of dollars for transportation and building decarbonization efforts.
Newsom’s plan would invest an additional $6.1 billion to accelerate the adoption of zero-emissions vehicles on top of the record $3.9 billion in last year’s budget, bringing the total to $10 billion over six years. The $6.1 billion in this year’s plan includes more than $3.5 billion for medium- and heavy-duty trucks, and school and transit buses.
“For California, you can’t get serious about climate change unless you’re serious about tailpipe emissions,” Newsom said in a press conference Monday. With such a large expenditure on EVs, “you’d think we were announcing for the United States government [but] this is a $10 billion state … commitment on zero-emission vehicles.”
Vehicle emissions account for roughly 40% of greenhouse gas emissions statewide; electrifying the transportation sector has been a top priority for Newsom and former Gov. Jerry Brown.
Brown ordered the state to put 5 million EVs on the road by 2030, and Newsom issued an executive order in September 2020 requiring all new passenger vehicles sold in-state to be emissions-free by 2035. (See Can California Meet Its EV Mandates?)
Last year, state lawmakers devoted a record $2.7 billion toward zero-emission vehicle programs in FY 2021/22 and $1.2 billion over the next two fiscal years. The funding for zero-emission trucks, buses and passenger vehicles was far more than the $1.5 billion that Gov. Gavin Newsom had proposed in January 2021. (See Calif. Earmarks $3.9B for ZEVs Through 2024.)
In his new plan, Newsom proposes adding $2 billion to fund projects needed for the state’s transition to 100% clean energy by 2045, including long-duration storage, green hydrogen and offshore wind infrastructure.
The past two summers saw CAISO’s grid stretched thin as the state relied more on solar power and imports to meet demand, both of which can dry up during Western heat waves that extend into evening hours. CAISO has connected about 2,250 MW of short-duration storage since the energy emergencies of summer 2020, but long-duration storage for wind and solar power is required to discharge for more than four hours. (See Long-duration Storage Needed for Decarbonization.)
In the building sector, Newsom proposed spending nearly $1 billion, including $622 million to retrofit low-income housing with electric appliances, efficient lighting and insulation. Another $300 million would fund consumer rebates for replacing gas furnaces, water heaters and kitchen ranges.
The California Energy Commission made the electrification of commercial and residential structures a key part of its 2022 building code update, requiring new homes to be wired for all-electric appliances and to use an electric heat pump either for space or water heating. (See Calif. Energy Commission Adopts 2022 Building Code.)
The current market share for heat pumps in California is less than 6% in new home construction; the requirement is expected to greatly increase demand and make heat pumps more affordable and widely available.
The requirements will reduce greenhouse gas emissions by 10 million electric tons, the equivalent of 2.2 million internal combustion passenger vehicles, in the next 30 years, the Energy Commission forecasted.
The governor’s total $286 billion budget plan is based on a second year of surplus revenue in California. This year’s surplus is estimated at nearly $46 billion.
Newsom’s proposal now must make its way through the legislature, with a revised plan scheduled to be issued in May.
A federal judge on Friday canceled a hearing to decide if Pacific Gas and Electric (NYSE:PCG) should face additional probation time after prosecutors said they would not ask for an extension based on state criminal charges.
“In light of the United States’ notice … that it will not seek to prove the allegations [of probation violations] … the hearing scheduled for Jan. 10, 2022, is hereby vacated,” Judge William Alsup wrote in a one-page order.
The utility’s five-year probation term for felonies related to the 2010 San Bruno pipeline explosion is scheduled to end Jan. 25. Prosecutors in Sonoma and Shasta counties have charged PG&E with starting wildfires in 2019 and 2020, and Alsup said last week he would consider extending PG&E’s probation based on the alleged crimes.
But U.S. Justice Department prosecutors Thursday said that they did not believe the court could extend PG&E’s probation because the sentencing judge gave the utility a maximum five-year term in January 2017. Any extensions would run concurrently with that sentence, meaning PG&E would still exit probation Jan. 25, they contended.
The prosecutors acknowledged that there appeared to be no case law backing their argument, leaving the matter ambiguous. They said in their report to Alsup that the state courts where PG&E faces charges are “the proper forum for development of the evidence.”
“Furthermore, if PG&E is convicted, a broader array of sentencing options will be available in that forum,” the prosecutors wrote.
Alsup, with the U.S. District Court in San Francisco, told federal prosecutors on Jan. 3 that he would give “serious consideration” to a request for additional probation time for PG&E based on charges that it started the 2019 Kincade Fire in Sonoma County and the 2020 Zogg Fire in Shasta County.
PG&E has been on probation since January 2017 for six felony convictions related to the San Bruno gas pipeline explosion in September 2010, which killed eight people and destroyed a suburban San Francisco neighborhood. One of the probation conditions is that PG&E does not commit any more crimes. Alsup found in November that PG&E had likely violated the probation terms by starting the Zogg and Kincade fires. (See PG&E Likely Violated Probation, Judge Finds.)
Sonoma County prosecutors filed 33 criminal charges against PG&E on April 6 in connection with the Kincade Fire, a 78,000-acre blaze that injured six firefighters, destroyed 374 structures and led to mass evacuations. The California Department of Forestry and Fire Protection (Cal Fire) found that a broken PG&E transmission line sparked the blaze.
In September, the Shasta County District Attorney’s office charged PG&E with four counts of involuntary manslaughter in the Zogg Fire. The wildfire killed an 8-year-old girl, the girl’s mother and two others. It burned more than 56,388 acres and destroyed 204 structures.
PG&E has accepted Cal Fire’s findings in both cases but denied criminal liability. It is fighting the charges in court.
Alsup, often a harsh critic of PG&E, said in last week’s hearing that he hopes the Shasta or Sonoma prosecutors will try to keep the utility on probation because it needs continued supervision to improve its safety practices.
Disasters caused by PG&E equipment have killed 110 people since 2010, a court-appointed monitor reported.
PG&E pleaded guilty to 84 counts of manslaughter in June 2020 for the Camp Fire, the deadliest wildfire in state history. A 100-year-old “C” hook on a PG&E transmission line broke, starting the fire that leveled the town of Paradise. (See PG&E Pleads Guilty to 84 Homicides and Arson.)
Prosecutors did not seek additional probation in that case. A plea deal called for PG&E to pay the maximum fine of nearly $4 million.
Connecticut is preparing to advance its program this year for fully electrifying the state transit bus system, Department of Transportation (ConnDOT) Deputy Commissioner Garrett Eucalitto said Thursday.
The state previously secured federal grants for the priority program, but funds from the Infrastructure Investment and Jobs Act will help kick the program into “high gear,” Eucalitto said during an Environmental Business Council of New England webinar.
CTtransit, which is a ConnDOT-owned bus service, has a fleet of 600 buses, and the department supports the purchases of about 180 other buses for smaller transit districts in the state, according to Eucalitto.
The department stopped buying diesel buses for CTtransit last year, and Gov. Ned Lamont signed an executive order in December directing the agency to discontinue funding purchases of any diesel buses by the end of next year.
“Every replacement bus we procure … is now going to be electric,” Eucalitto said. “We intend, within the next 13 years, to have a 100% electric transit fleet in this state.”
Last January, ConnDOT secured a deal with New Flyer of America for the purchase of 12 Xcelsior Charge battery-electric buses (BEBs), with an option to purchase up to 63 more buses over two years. CTtransit activated the first bus for that new fleet in Hamden in October. The $21.8 million project includes the purchase of the 12 buses and associated direct-current fast chargers from ABB, as well as upgrades to electric infrastructure and bus facilities.
The biggest challenge for the entire fleet transition, according to Eucalitto, will be updating the infrastructure for the fleet garages.
“A lot of people think purchasing the buses will be the expensive part and the difficult part, but we have a lot of depots that are spread across the state, and it’s going to be difficult for us to really get in, upgrade the electrical systems and potentially build some substations,” he said.
For the Massachusetts Bay Transportation Authority, investing in bus facilities is the “most challenging” part of electrifying its 1,100 buses by 2040, according to Jamey Tesler, CEO of the Massachusetts Department of Transportation.
The authority’s facilities are “older,” and they have “many different requirements to be upgraded and modernized,” he said during the webinar. A near-term priority plan for the authority will see the replacement of a 100-year-old garage in Quincy that services the fleet’s oldest diesel buses.
“In 2024, when [the Quincy] facility is complete, we’ll be able to replace our highest-emissions diesel buses with a battery-electric bus fleet,” Scott Hemway, director of bus modernization at Boston’s Massachusetts Bay Transportation Authority (MBTA), said during a Dec. 9 public meeting.
In 2027, the authority is planning to complete an upgrade to its Arborway bus maintenance facility in Boston that will support the transition from 118 compressed natural gas buses to 200 BEBs. The entire fleet transition, according to the MTBA, will require facility upgrade investments totaling $4.5 billion through 2035.
“Because these facilities are challenging to build, they are very expensive, but they are an essential ingredient in the equation to bring about an electric fleet over time at the MBTA,” Tesler said.
The agency is still in the process of identifying funding for construction of the Arborway facility, which is slated to begin in 2024.
MISO flirted with its first maximum generation event of the year early Friday, a month after it cautioned members that winter operations could be risky.
The grid operator announced conservative operations and a maximum generation warning before dawn Friday in its Central and North regions, where high temperatures were in the single digits and generation was forced offline. MISO’s morning peak surpassed 97 GW. By 9:30 a.m. EST, the RTO was able to end both the warning and conservative operations.
Real-time prices topped $230/MWh in MISO’s Indiana and Illinois trading hub during the evening peak.
The close call followed several warnings by MISO executives about natural gas and coal fuel security and forced generation outages during cold fronts. (See MISO Sounds Alarm on Potential Winter Fuel Scarcity.)
MISO maximum generation warnings direct market participants to update generation resource availability and load-modifying resource availability. They also ask transmission owners to ready reconfiguration options. Under conservative operations, members are asked to determine whether any generation or transmission maintenance can be rescinded or postponed.
To better manage winter hazards, the RTO is collecting weekly fuel surveys through February from about 400 generators to assess natural gas and coal fuel security. The task is unpopular among some generation owners, but MISO has been firm that it needs to better understand fuel positions during winter.
The grid operator also issued a cold-weather alert New Year’s Day for the Dakotas, Minnesota and Manitoba, Canada. MISO expected some areas within those states and province to see temperatures drop to -20 degrees Fahrenheit, prompting fuel restrictions. That alert did not escalate.
The RTO has singled out January as its riskiest period for the remainder of the planning year. It has said it expects a 101-GW system peak this month and 108 GW in available capacity to meet the demand. (See MISO Warns of January Emergency Procedures.)
A clean energy group that fears the Southeast Energy Exchange Market (SEEM) will stifle renewables is hoping that new appointees to the Tennessee Valley Authority will eventually lead to a more cost-efficient RTO.
The TVA board of directors will soon vote on whether to integrate into the new market. It next meets Feb. 10.
Maggie Shober, research director for the Knoxville, Tenn.-based Southern Alliance for Clean Energy (SACE), said President Biden’s four nominees to the TVA board could shake up the agency’s prevailing opinion on SEEM.
“I think they could take a critical look at SEEM and see if it aligns with their vision and the administration’s vision on what TVA could be and how they could lead the clean energy transition,” she said in an interview with RTO Insider.
However, Shober noted that Biden’s nominees have yet to receive a hearing. All five current TVA board members were appointed by former President Donald Trump. Only Jeff Smith has an energy background.
Shober also noted that two more board seats will open in May, when Smith’s and A.D. Frazier’s terms expire. At that point, the TVA board would dip below quorum.
Shober said SEEM would block independent and small developers’ renewable projects, and its design wouldn’t dictate any changes to utilities’ integrated resource plans.
“The IRP point is important because SEEM will not encourage or prevent any renewable development,” Shober said. “That’s not only likely to not be enough, but it will keep projects uncertain. You have to know that there’s going to be a buyer, and a buyer that is not going to block a project.”
“There are so many question marks about how this will work in practice and not lead to market manipulation,” Shober said, adding that SEEM participants seem to be “trying hard to preserve their business models” while avoiding a new RTO or energy imbalance market.
TVA has a goal to lower its carbon emissions 80% from 2005 levels by 2035; it plans to achieve net-zero carbon emissions by 2050.
TVA spokesperson Ashton Davies said the federal utility is “committed” to SEEM.
“SEEM will provide an avenue for TVA and neighboring utilities to more easily buy and sell energy intra-hour, including excess renewable energy,” she said in an emailed statement. “This platform aims to lower customer costs and optimize renewable energy resources, which supports TVA’s mission of serving the valley.”
TVA currently operates or contracts more than 1.6 GW of solar power.
Shober’s preferred approach is one where the Southeast and TVA create their own RTO, something she admits is a “long shot.” But she says SEEM might be useful in the long run.
“If there’s anything that comes out of the SEEM development, it’s that the utilities can work together and be constructive with something,” she said.
However, Shober said SEEM will likely derail more efficient and green market designs under consideration in the Southeast that could hasten a clean energy transition.
And she doubts that SEEM can evolve into a more fleshed out market for its participants. “I think the way it’s setting up with an algorithm and no central governance makes it harder to adapt it into something else,” she said.
A Vibrant Clean Energy report last year showed that an RTO design would save the Southeast $119 billion over a SEEM model by 2040. The report also said an RTO would facilitate the utilities’ clean energy goals and create about a million new jobs in the electricity sector.
Shober said she believes SEEM serves to dampen growing interest in a wholesale energy market in the Southeast.
“I think utilities were hoping to quell some of that,” she said. “This is not the kind of savings you’d see under an RTO.”
SACE has said that the SEEM utilities’ savings claims of $40 million annually would, at most, amount to $1/year for residential customers whose utilities are served by the new market.
Shober said TVA’s inclusion will give SEEM a needed east-to-west direction. She pointed out that Associated Electric Cooperative Inc. likely wouldn’t be able to connect with Duke Energy or Southern Co. without TVA’s participation in the new market.
Shober also said documents obtained through a recent request under the Freedom of Information Act from SACE show that TVA — along with Southern and Duke Energy — spearheaded SEEM’s creation as early as last January.
“It’s pretty clear that TVA was involved in developing the SEEM idea from the get,” Shober said.
The state of Nevada is awarding up to $8 million in grants to replace diesel trucks and buses with cleaner vehicles while offering a caveat to recipients: The diesel vehicles must be permanently taken out of service.
The grants are the latest round of funding from the Diesel Emission Mitigation Fund (DEMF), which was created with the state’s share of Volkswagen settlement money. The application deadline is Jan. 31. Details on applying are here.
The funds are available to public agencies and private businesses in the state to help replace diesel-powered vehicles and equipment, including medium- and heavy-duty trucks and school buses, shuttle buses, or transit buses. Forklifts, locomotive freight switchers and airport ground support equipment are also eligible.
The grant will cover the difference between the cost of a new, diesel-powered vehicle or piece of equipment and the cost of a zero-emission or alternative-fuel replacement.
Applicants who received funding in previous cycles of the DEMF are not eligible in this round, according to the Nevada Department of Environmental Protection (NDEP), which is administering the grants.
Early Retirement
One key to the grants is that they are funding only the early retirement of diesel vehicles. Proposals to replace diesel equipment or vehicles that are scheduled to be retired within the next three years will not qualify.
And once funds are awarded, the recipient must render “permanently inoperable and available for recycle” the diesel vehicle or equipment being replaced, according to an NDEP webinar on the grant opportunity.
That includes drilling a hole 3 inches or larger in the engine block and cutting the chassis in half between the front and rear axles.
“You can’t take your old piece of equipment and sell it on the used vehicle market,” Sig Jaunarajs, supervisor of the Planning and Mobile Sources Branch at NDEP, said during the webinar.
“The idea is … that piece of equipment is going to die and will not be producing emissions anymore,” Jaunarajs said. “That’s how we can count that emissions benefit.”
While NDEP will work with grant recipients in cases in which drilling a 3-inch hole in the engine block is difficult, Jaunarajs said, it won’t be enough to drill a quarter-inch hole “that you can plug very easily and that engine will come back to life.”
Documentation such as photos will be required to show that the vehicle is permanently out of service.
VW Settlement
The Diesel Emission Mitigation grants are being funded by Nevada’s share of the Volkswagen settlement.
Volkswagen pleaded guilty in 2017 in a criminal case alleging it installed “defeat devices” on diesel vehicles sold in the U.S. in order to cheat on emissions tests. In settlements of a civil case with the U.S. and California, VW created a $2.9 billion trust fund to be used to offset excess emissions of nitrogen oxides, NDEP said.
Nevada is receiving $24.8 million through the settlement, with $19.5 million going toward DEMF projects; $4.1M for the Nevada Electric Highway, an EV charging infrastructure program; and $1.2M for the Nevada Clean Diesel program.
Two previous cycles of the DEMF program issued $9.2M to fund the replacement of 29 trucks, 22 school or transit buses and 174 pieces of airport ground support equipment.
Eighty percent of the funded projects involved replacing diesel vehicles or equipment with battery-electric alternatives.
Although NDEP has about $8 million remaining in VW settlement money, officials said during the webinar that they don’t expect to use it all during this funding cycle.
More than 100 insurance companies are suing ERCOT and power generators for their policy holders’ “significant property damage” during last February’s winter storm, adding to the mountain of legal woes facing the Texas grid operator.
The 137 companies banded together to file their lawsuit Dec. 28 in the Travis County District Court’s 459th Judicial District and asked for a jury trial (D-1-GN-21-007413).
They included as defendants 37 “power generation companies” — from industry heavyweights Luminant and NRG Energy down to individual wind farms — for failing to prepare for the 2020-2021 winter season by adhering to voluntary weatherization standards.
The insurance companies charge that ERCOT and the generators were “at fault” for the dayslong power outages that resulted in hundreds of deaths and billions in property damage. According to a report from the Texas Department of Insurance, insurers have received more than 500,000 claims stemming from the winter storm. The report estimated that, as of July 2021, the companies will have to pay about $10.3 billion in losses.
The lawsuit said that while ERCOT has conducted weatherization-compliance spot checks since 2013, staff would regularly find that 25 to 35% of the generators were deficient and/or not complying with weatherization rules.
“ERCOT and the [generators’] unwillingness to accept or adopt any minimum weatherization standards runs contrary to the common law of Texas,” the insurance companies said.
According to the lawsuit, Texas courts hold electric companies to the burden of showing they exercise “due care” in supervising and maintaining their facilities. It cited precedent that the interruption of service is not an event “that occurs without a cause.”
“When a power failure occurs, there is a defect somewhere says,” the lawsuit said.
ERCOT did not respond to a request for comment. However, the grid operator has consistently claimed sovereign immunity when sued, noting it is funded by generators’ transaction fees.
The issue could be decided in two unrelated cases before different state appellate courts. ERCOT is battling San Antonio municipality CPS Energy in the Fourth Court of Appeals over charges of “exorbitantly high, illegal” wholesale costs during the storm. (See CPS Energy Wins Round 1 vs. ERCOT.)
Separately, the Fifth Court of Appeals in Dallas has heard arguments over a 2016 complaint against ERCOT by Panda Power Generation Infrastructure Fund. Panda argues that it spent $2.2 billion to build three new power plants based on the grid operator’s faulty and misleading projections of the state’s future energy needs.
In other litigation, more than 400 Texans have filed 170 lawsuits against ERCOT and utilities over the February outages. The state officially lists the death toll at 246.
Gas Production Drops Again
FERC, NERC, academia and the electric industry have reached consensus that February’s outages were mostly from gas infrastructure’s lack of winterization, which reduced fuel supplies to gas-fired generation units. (See FERC, NERC Release Final Texas Storm Report.)
This past weekend, gas supplies again dropped during Texas’ first cold snap of the season. Bloomberg said gas production in West Texas’ Permian Basin fell to its lowest levels since last February, leading to the loss of more than 10% of ERCOT’s generation.
Naturally, that raised questions among industry experts and observers.
“Yes, poor performance of gas suppliers last weekend ‘raises questions,’ but more importantly, it provides answers,” tweeted Stoic Energy President Doug Lewin. “The answers are they didn’t winterize; they’re not ready; and Texans are again vulnerable if there’s another extreme cold snap like 2011 or 2021.”
Lewin is among those who have criticized the gas industry’s lack of winterization, saying the electric industry’s more robust winterization practices are rendered useless when gas doesn’t flow. (See ERCOT, PUC Say Grid is Ready for Winter Weather.)
The Texas Railroad Commission, which regulates the state’s natural gas industry, has not required gas facilities to winterize this winter, as has the electric industry. Gas companies can also opt-out by paying a $150 fee and asking for an exemption. The gas network is being mapped to determine those facilities critical to power production, but that process isn’t expected to be finished until 2023.
The cross-industry group working on the study have filed a progress report with the Public Utility Commission. It lists several best practices that “should be implemented … to prepare facilities providing natural gas critical to the electricity supply chain to maintain service in an extreme weather event.”
