Search
`
November 9, 2024

Posted on

Can Youngkin Stop Clean Energy Growth in Virginia?

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 (Resources for the Future and Virginia Energy) Content.jpgGetting 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.

Posted on

California Governor Proposes Spending $10B on EVs

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.

Posted on

Judge Refrains from Adding Time to PG&E Probation

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.

Cal Fire concluded in March that the fire began on Sept. 27, 2020, when a leaning gray pine tree fell onto a PG&E power line in rural Shasta County. (See PG&E Equipment Started Zogg Fire, Investigation Finds.)

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.

Posted on

Electric Bus Program to ‘Kick into High Gear,’ ConnDOT Says

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.

Posted on

Near-emergency Follows MISO’s Winter Warnings

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.)

Posted on

Clean Energy Group Denounces TVA’s SEEM Membership

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.”

SEEM is set to go live later this year. (See SEEM to Move Ahead, Minus FERC Approval and Panelists: SEEM Can’t Be Southeast’s End Goal.) SACE joined the Sierra Club, the Sustainable FERC Project, the Natural Resources Defense Council and other Southern public interest organizations in opposing SEEM’s creation.

“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.

Posted on

Nevada Awarding $8M to Replace Diesels

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.

Posted on

Insurance Companies Suing ERCOT, Generators

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.

The Texas Supreme Court last March declined to review an appellate ruling granting ERCOT immunity from lawsuits. (See Texas Supremes Sidestep Ruling on ERCOT Lawsuit Shield.)

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.”

Posted on

New Jersey Targets Port Cargo-handling Emissions

This year is going to be a cleaner, greener one at the Port of New York and New Jersey as a new rule went into effect Jan. 1, requiring that certain new cargo-handling equipment at the facilities be zero emission.

Similarly, the New Jersey Department of Environmental Protection began the year with a proposed rule aimed at cutting carbon dioxide and other polluting emissions — such as nitrous oxides and fine particulate matter (PM2.5) —produced by cargo-handling equipment at the Port of New York and New Jersey and several far smaller ports in South Jersey.

Based on similar regulations enacted in California, the DEP’s proposed rules, would require owners and operators of new and existing diesel-powered cargo-handling equipment to replace it with newer, less polluting models or install a cleaner engine into existing equipment. The requirements cover a variety of vehicles, from the yard tractors that move containers around the terminal to mechanical equipment that can pick up, stack and load and unload containers to and from trucks.

The DEP will be seeking public comment on the proposed rules over the next two months.

Specifically, the proposal aims to cut the emission of nitrogen oxides (NOx) and PM2.5 “through replacement with engines or equipment that meet the most stringent emissions control technology standard or through the application of the most stringent emission control strategy.”

Long-term exposure to PM2.5 has been associated with asthma, lung cancer and premature death, while NOx contributes to ozone, which can damage an individual’s respiratory tract and cause breathing difficulties, said the DEP statement outlining the rules.

The zero-emission mandate is part of the operating rules, or port tariff, issued by the Port Authority of New York and New Jersey (PANYNJ) to all companies that lease terminals at the port, with modifications introduced at the start of each year. The latest addition requires that certain new cargo-handling equipment added to the port’s vehicle fleet be zero-emission, which the authority says can only be fulfilled with electric equipment.

The PANYNJ’s new guidelines follow the port’s Oct. 28 commitment to cut the port’s greenhouse gas emissions in half by 2030 and reach net-zero emissions by 2050, in part by reducing the emissions from the 1,200 pieces of cargo-handling equipment at the facility. Overseeing the largest port on the East Coast, the PANYNJ said it would reach those goals by transitioning “to clean zero-emissions electric port material-handling equipment, to the maximum extent practicable.”

The new tariff requires that any new ship-to-shore cranes, which move cargo on and off ocean vessels, and rail-mounted gantry cranes, which move and stack containers, must be zero emission equipment. Likewise, any new yard tractors, which move containers internally around the port, added to the port fleet after Jan. 1, 2025, must be zero-emission vehicles.

The tariff also requires that other types of new equipment that serve the port’s cargo and cruise ship terminals must meet Tier 4 emissions standards, which are the Environmental Protection Agency’s (EPA) toughest standard for NOx and PM2.5 emissions from diesel engines. The EPA has estimated that the standard could cut PM2.5 and NOx by more than 90%.

Seeking Environmental Justice

The DEP rules are Gov. Phil Murphy’s latest effort to cut emissions from the transportation sector, the largest source of emissions in New Jersey. As in other states, the challenge is particularly urgent around ports, due to the volume of diesel trucks and other equipment used and the proximity of low-income and minority communities, which raises environmental justice concerns.

Murphy is seeking to put the state on course to generate zero emissions by 2050, with a strong focus on promoting the use of electric vehicles, especially trucks. The governor has worked to increase the number of EV chargers around the state and allocated funds to provide incentives to subsidize the purchase of EV truck and vehicles. Last month, the state adopted rules that require truck manufacturers to make electric trucks a rising proportion of their vehicle sales in the state. (See NJ Adopts EV Truck Sales Mandate.)

The DEP’s cargo-handling equipment rules are aimed at the owners and operators of port or rail terminals that use equipment such as yard trucks or gantry cranes. The proposed rules would also apply to anyone who uses, sells, leases, rents or purchases the equipment, and would cover other ports on the Delaware River, among them Camden, Paulsboro and Salem, as well as rail yards in Newark, Elizabeth, Jersey City and South Kearny.

Norfolk Southern and CSX Transportation, which operate the rail yards, did not respond to a NetZero Insider request for comment. However, Andy Saporito, executive director of the South Jersey Ports Corp., which operates four cargo terminals, said his team will review the rules and develop a plan to meet them.

“We strive to operate our ports cleaner and greener,” he said, noting that his agency has already taken steps in line with the rules. Two years ago, the ports spent $2 million to upgrade a portion of their fleet to low-emission movers, cranes and vehicles, and was awarded $6.6 million in 2021 to buy 23 electric yard tractors.

The DEP rules require that all cargo-handling equipment in the covered facilities meet either California emission standards or the EPA’s Tier 4 standards within certain time frames, depending on the type and age of the equipment. Equipment that is more than 20 years old must be brought in line with the rules within two years, but equipment made since 2007, which is inherently cleaner, must be replaced or upgraded within five years.

If no replacement equipment is available that meets either standard, the DEP will, in certain circumstances, approve an alternative. In addition, the DEP might approve equipment that does not meet all its requirements if the average of all the vehicles in a fleet meets the emissions standards.

The Challenge of Reducing Port Emissions

Based on data compiled by PANYNJ, the DEP estimates that by 2028, the “emissions benefits” of the rules will be 6.4 fewer tons of PM2.5 emitted and 82 fewer tons of NOx. The cumulative benefits from 2024 to 2035 would be a reduction of 38 tons of PM2.5 and 500 tons of NOx, the DEP said.

Yet the DEP’s outline of the rules also shows their limits and the challenges facing the state in seeking to cut emissions at its ports. Cargo-handling equipment, said the 2019 Multi-Facility Emissions Inventory compiled by the PANYNJ, was only the third largest source of pollution, accounting for 18% of PM2.5 and 9% of NOx at the Port of New York and New Jersey.

According to the inventory, only about 40% of the 1,200 pieces of cargo-handling equipment at the port are below the Tier 4 emissions standard set out by the DEP, and so would have to be replaced if the proposed rules were to take effect.

The largest source of emissions at the port, heavy duty vehicles, accounted for 42.8% of the PM2.5 and 32.4% of NOx, the report said.

Nevertheless, the report also shows that the authority has had some success in cutting emissions. The NOx and PM2.5 emissions at the port have declined since 2006, despite a 47% increase in the volume of cargo handled.

Some port stakeholders have taken steps to cut emissions on their own. In August, Red Hook Container Terminals, which operates the smallest of six container terminals in the port, unveiled a fleet of 10 Chinese-made electric yard tractors, which move containers around the port. (See: Port of NY-NJ Unveils Fleet of 10 EV Trucks).

The state provided partial funding for the tractor purchase, using money from the Volkswagen settlement. Another $850,000 from the settlement was allocated to purchase a mobile electric crane at the Port of New York and New Jersey, while $2.3 million went to two straddle carriers, which move containers at the port, and $6.6 awarded to buy the 23 electric yard tractors at South Jersey ports. (See: NJ Targets Ports for EV Incentives).

Posted on

FERC Denies Motion of Kittell Estate in GreenHat Case

FERC on Wednesday denied a motion from the estate of one of the owners of GreenHat Energy for the commission to drop its enforcement action after it emerged last fall that Office of Enforcement lawyers violated regulations related to the electricity market manipulation case (IN18-9).

Lawyers for the estate of Andrew Kittell, one of three owners of GreenHat, made a filing in October, arguing that a series of emails between Enforcement’s Division of Investigations (DOI) lawyers Thomas Olson and Steven Tabackman were “not only unlawful, but deceptive.”

FERC released the emails after Olson, who is part of the litigation staff in the GreenHat proceeding, disclosed them to Enforcement management. (See Estate of GreenHat’s Kittell Lobbies FERC to End Enforcement Action.)

In November, FERC said it determined that GreenHat and its owners violated the Federal Power Act by “engaging in a manipulative scheme” in PJM’s financial transmission rights market, issuing a total of $242 million in fines for the company’s 890 million-MWh default in 2018. The commission assessed civil penalties of $179 million on the company and $25 million each on owners John Bartholomew and Kevin Ziegenhorn. It also directed GreenHat, Bartholomew, Ziegenhorn and Kittell’s estate to disgorge more than $13 million in unjust profits, plus applicable interest. (See FERC Levies $242M in Fines on GreenHat, Owners.)

GreenHat acquired the largest FTR portfolio in PJM between 2015 and 2018, but defaulted on the portfolio in June 2018, leaving PJM stakeholders to cover more than $179 million in the market. When the company defaulted, FERC said, GreenHat had only $559,447 in collateral on deposit with PJM. (See Doubling Down — with Other People’s Money.)

<img src="//www.rtoinsider.com/wp-content/uploads/2023/06/140620231686782829.jpeg" data-first-key="caption" data-second-key="credit" data-caption="

GreenHat’s significant growth in exposure and MTA loss

” data-credit=”PJM” style=”display: block; float: none; vertical-align: top; margin: 5px auto; text-align: center;” alt=”GreenHats-significant-growth-in-exposure-and-MTA-loss-PJM-Content-2-1″>GreenHat’s significant growth in exposure and MTA loss | PJM

 

FERC said in Wednesday’s order that it was “troubled by the exchange of emails between decisional staff and litigation staff,” but the email exchange did not rise to the level of having to dismiss the case.

“The commission reviewed the prior allegations regarding the investigative process in this case and found such allegations to be without merit,” FERC said in its order. “With regard to the October 2021 notice, we need not decide here whether the Tabackman-Olson email exchange identified in the notice violated the commission’s regulations because we conclude that the conduct at issue here would not warrant the extraordinary remedy of dismissal.”

Email Exchange

In the email exchange disclosed in October, Olson notified the commission that he received emails through his personal Gmail accounts on Sept. 17 and 18 from Tabackman, who was serving as decisional staff in the GreenHat case. The two were discussing a pair of U.S. Supreme Court case decisions that Tabackman believed could strengthen FERC’s case.

Tabackman urged Olson not to reveal where he received the information on the cases, saying, “You never heard that here.”

Olson questioned Tabackman on whether the latter sent information on 1940’s U.S. v. Summerlin and 2006’s Marshall v. Marshall with the GreenHat case in mind, “or something else?”

Tabackman responded, “Yes — you should be familiar with them — though you should not mention how you came upon them.”

After receiving another email from Tabackman on Sept. 18 that referenced Tabackman’s work with the decisional team, Olson realized the emails “constituted a violation of the commission’s separation-of-functions regulation.”

The regulation prohibits any employee assigned to work on an enforcement proceeding or assisting in a trial “to participate or advise as to the findings, conclusion or decision, except as a witness or counsel in public proceedings.”

FERC removed Tabackman as a counsel of record in its federal court case.

In its motion, lawyers for the estate of Kittell, who killed himself by jumping off the San Diego-Coronado Bridge in California on Jan. 6, 2021, argued that the commission should drop all enforcement action against the estate, ban Tabackman and Olson from any future involvement in the investigation and “order other offices within the commission to investigate what happened.”

FERC said in its order on Wednesday that the email exchange “addressed procedural matters that might arise under California probate law in the state probate proceeding on the Kittell estate.” The commission said the procedural matters discussed in the emails were not an issue before FERC, but it decided to refer the matter to the OIG for an investigation.

The commission said the OIG “declined to take further action and deferred to the commission to proceed as appropriate” after finishing its investigation. “FERC said the commission’s Designated Agency Ethics official and staff conducted an internal administrative inquiry into any other communications regarding the Kittell matter and found no other violations.

FERC said it expects its staff to “conduct themselves in accordance with the highest ethical standards and is committed to ensuring that the subjects of investigations receive due process, both in perception and reality.”

“Because the commission ‘is charged with safeguarding the integrity of our nation’s interstate energy markets,’ it is obligated to take necessary and appropriate action when it finds violations of the statutory and regulatory prohibitions on manipulation of those markets,” FERC said in its order. “Moreover, numerous courts have recognized that administrative agencies are charged by Congress to enforce laws on behalf of the American people and thus dismissal of an agency enforcement action may run counter to the public interest. Accordingly, absent extreme circumstances such as a violation of Constitutional due process, courts generally will not set aside agency decisions based upon a violation of procedural rules.”

The commission determined that there was “no evidence” that the Kittell estate was harmed by the email exchange between Tabackman and Olson.

“To the degree that there was any harm from the email exchange, OE staff appropriately remedied that harm by immediately disclosing that exchange, thereby providing respondents with an opportunity to respond, and, as discussed, the commission both referred the matter to the OIG and tasked the commission’s designated ethics official to conduct an inquiry to assess whether additional prohibited communications occurred to confirm our decisions in this case were reasoned and unbiased,” FERC said in its order. “Accordingly, we find that dismissing the action would serve no purpose other than to deprive the public of justice in the underlying matter.”

Danly Dissent

FERC Commissioner James Danly issued a dissent in the order. Danly previously had harsh words for PJM in the case, saying the RTO was partially to blame for the result of the default and had a “share of the blame that must rightly be assigned to PJM.”

In his dissent issued Wednesday, Danly said the ethics of prosecutors “must be above suspicion,” and for the commission to do “anything less than fully consider and respond to these claims damages our credibility.”

“Under these circumstances, the movant and the public deserve an answer,” Danly said in his dissent. “And while I acknowledge that enforcement and the commission have taken some action to redress enforcement’s misconduct, our enforcement program would be better served by issuing a commission order with a clear-eyed and unflinching response to the misconduct alleged in both the Oct. 5, 2021, motion and the respondents’ answer to the order to show cause.”