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October 5, 2024

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Report: NY Road Transport Emissions Up 12% Since 1990

New York’s first climate law-compliant greenhouse gas emissions report has found the state’s overall emissions are down from 1990 levels, but transportation stood out in the analysis as the top sector needing improvement.

Emissions increases in a group of sectors reveal the state has “enormous challenges” ahead in its work to reduce emissions 85% from 1990 levels by 2050, Department of Environmental Conservation Commissioner Basil Seggos said in a statement.

The Dec. 30 report, which covers 1990-2019, found that statewide GHG emissions decreased 6% for the period and 17% from 2005 to 2019. Road transportation emissions, however, increased 12% for the 30-year period and represented 17% of statewide total emissions in 2019.

While the report said the increase for road transport was substantial for the 30-year period, the biggest jump happened between 1990 and 2005. In that time, emissions grew from 56 million metric tons of carbon dioxide equivalent (MMT CO2e) to 69.8 MMT CO2e, then they dropped over the next 12 years to 62.8 MMT CO2e and stayed flat through 2019.

The state’s buildings sector, while having higher total emissions than the transportation sector, had an overall decline from 1990 to 2019 from 87 to 72.6 MMT CO2e. Of the residential, commercial and industrial subsectors, however, residential building emissions showed the only overall increase for the period. The subsector emissions increased from 39 to 46 MMT CO2e in the first 15 years after 1990, then they settled at 40.7 MMT CO2e in 2019 following some minor annual fluctuations caused by weather patterns.

Overall for the buildings sector, emissions increased 40% from natural gas and decreased 54% from other fuels, which include wood, distillates and coal.

The most significant sectoral emissions reduction between 1990 and 2019, at 65%, occurred in fuel for electricity caused by the transition away from the combustion of coal and petroleum fuels to natural gas, according to the report.

Coal emissions for electricity dropped from 25 to 0.46 MMT CO2e for the period, while natural gas emissions increased from 12.6 to 20.7 MMT CO2e.

Other Trends

In the agriculture sector, livestock management had the highest emissions, increasing 44% from 1990 to 2019. While animal feeding practices produced the highest emissions for livestock activities, manure management specifically saw the biggest emissions increase for the period. That trend, the report said, is because of policy changes regarding manure storage that protect water quality.

Activities in the forestry and land-use sectors removed 32.7 MMT CO2e in 1990 and 29.1 MMT CO2e in 2019. New York’s forest lands were the single largest emissions sink, but they sequestered 2.2 MMT less CO2 in 2019 than in 2005 because of forest land conversion, the report said.

Tracking of specific greenhouse gases showed that CO2 emissions declined by 39 MMT, or 15%, from 1990 to 2019, but hydrofluorocarbon emissions increased from near zero to 20 MMT CO2e for the period. That increase, the report said, is attributed to uptake in the residential and commercial buildings and industrial sectors as a refrigerant following the phase down of chlorofluorocarbon use.

The New York Climate Action Council, in its recently adopted draft scoping plan, recommended the state consider advancing a transition away from high global warming-potential (GWP) HFCs to low or ultra-low GWP HFCs or natural refrigerants.

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NJ Ramps up Wind Sector Support

New Jersey is doubling down on its efforts to create a new offshore wind sector, with $350 million set aside to award corporate tax credits to companies that make major investments in the sector and another $265 million allocated to help fund the creation of the New Jersey Wind Port.

The $265 million, which Gov. Phil Murphy and the legislature allocated in November from a fund created to pay down state bond debt, brings the total committed to the wind port to about $500 million. The funding commitments for the wind port, which is located on the Delaware River in Lower Alloways Creek, are now more than 25% higher than the project cost estimates of $300 million to $400 million released when Murphy first announced the project in June 2020.

In a separate move, the New Jersey Economic Development Authority (NJEDA) in December started accepting applications for a program, the Offshore Wind Tax Credit Program, that the agency expects will typically offer tax credits equal to 40 to 60% of a company’s qualified capital investments in a “major, land-based offshore wind industry project.” To be eligible, a business must invest $50 million or more in the project, or invest $17.5 million in the project if the company is a tenant in a space that the owner invested $50 million or more.

New Jersey is increasing its commitment to the wind sector as other states on the East Coast — among them Virginia, New York, Massachusetts and Maryland — are making their own investments to create an in-state offshore market that also could attract supply chain business from out-of-state projects.

“To me, the story is New Jersey is putting our money where our mouth is,” said Brian Sabina, chief economic growth officer for NJEDA, which oversees much of the expenditures on the wind port. “We are crystal clear that we believe New Jersey is, and will continue to be, one of, if not the, hub for offshore supply chain developments in the offshore wind industry in the U.S.”

New Jersey’s latest round of offshore wind funding follows a commitment of $200 million to the wind port put in the state budget by Murphy and the legislature in June and a $13 million commitment to the project by the New Jersey Board of Public Utilities (BPU). In addition, the governor and legislature awarded $44 million to the state Department of Transportation for a dredge project that will deepen the channel connecting the port and the main channel of the Delaware River.

Sabina said that the state is “not done” with allocating money to the project and suggested that one source of future funds could be the federal government, including the Build Back Better bill. However, that bill stalled in mid-December.

“This is not a one-year, one-time investment,” Sabina said of New Jersey’s commitments. “This is to start getting ahead on making the down payments on the infrastructure we need to drive our economy and our [economic] climate in the right direction.”

Proven Demand

New Jersey has set a target date of 2024 to complete the port, which broke ground Sept. 9. The port, and the effort to shape it as a hub that will serve the regional wind industry supply chain, are key parts of Murphy’s goal to create a state offshore wind sector that will generate 23% of the state’s energy by 2050. The state aims to create wind projects totaling 7,500 MW by 2035. (See NJ Breaks Ground On Offshore Wind Hub.)

The plans outlined on the wind port website, which calls it the first purpose-built wind port on the East Coast, include a 30-acre marshalling area for component assembly and staging; a dedicated overland heavy-haul transportation corridor; and a heavy-lift wharf with a dedicated delivery berth and an installation berth that can accommodate jack-up vessels. Nacelle manufacturers MHI Vestas and General Electric have committed to creating nacelle plants at the port, and the developers of the three offshore wind projects approved by New Jersey so far have also agreed to use the port. German manufacturer EEW Group is building a monopile factor in the nearby Port of Paulsboro. (See New Jersey Shoots for Key East Coast Wind Role.)

The BPU in 2019 approved the 1,100-MW Ocean Wind 1 project, developed by Danish developer Ørsted, and on June 30 approved Ørsted’s 1,100-MW Ocean Wind 2 and the 1,510-MW Atlantic Shores project, a joint venture between EDF Renewables North America and Shell New Energies US. The BPU is planning to hold three more solicitations over the next five years.

Sabina said the number of companies interested in putting money into New Jersey’s offshore wind industry and wind port shows the state’s commitment is well placed. He cited the fact that 16 companies submitted nonbinding offers to become tenants at the wind port, including Siemens Gamesa Renewable Energy, Vestas-American Wind Technology and Beacon Wind. (See NJ Wind Port Draws Offshore Heavy Hitters.)

“Demand for this infrastructure is there,” Sabina said. “And that’s giving us the confidence to say, ‘Let’s start making sure that we’re ahead of the game in terms of the next phase of design and construction.’”

Jockeying for Out-of-state Investors

Sabina said the tax credit program grew out of the awareness that a vigorous competition between states and countries is underway for investment dollars in the offshore wind sector. New Jersey needed a way to attract “major Tier 1 suppliers and other major large, maybe Tier 2, manufacturing facilities to come and anchor their supply chains here in our state,” he said.

“We know that those same companies are considering investing in other states. We know those same companies are considering investing in other regions,” he said. “We needed a tool to help make sure that when we talk with those companies — Siemens, EEW, Vestas, GE — we had a tool to help them partner and help them de-risk their investments in our state.”

Applicants can apply for a tax credit that is equal to up to 100% of the investment, and the recipient can use the credit to reduce taxes or sell it to someone else seeking to do the same. To be eligible for a credit, companies must be in a business that is located in the state and is “related” to the offshore wind industry. The company, along with meeting the capital investment requirements, also must create jobs, starting at 100 jobs in the first year and rising to 300 jobs by the fifth year.

To get a credit equal to 100% of the project investment, the developer must show that New Jersey will receive an amount in sales, payroll, property and other taxes that is equal to 110% of the total capital investment. NJEDA officials say that their modeling shows most applicants will be eligible for credits equal to 40 to 60% of their capital investment.

“That’s really what this tool is about,” Sabina said. “If you’re going to do a large major manufacturing facility or other large offshore wind project, we want to have a tool to co-invest with you so that you can anchor your supply chain in our state, in our region.”

A similar effort to create an in-state industry has spurred efforts in Virginia, which announced in October that Siemens will establish a new plant for offshore wind blades at the Portsmouth Marine Terminal. That announcement followed two months after Dominion Energy said it would create a staging and assembly facility on 72 acres at the terminal.

In Maryland, developers of two offshore wind projects awarded by the Public Service Commission said they would use port facilities at Tradepoint Atlantic in Sparrows Point outside Baltimore and in Ocean City for marshalling, operations and maintenance. Sparrows Point is also the site of a planned monopile plant.

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New York to Invest $500M in OSW Infrastructure

New York will invest $500 million in offshore wind manufacturing and supply chain infrastructure and electrify 2 million homes by 2030, Gov. Kathy Hochul said Wednesday in her 2022 State of the State address.

The state entered 2022 having approved the largest transmission projects in New York in 50 years, with its first OSW project, South Fork, ready to put steel in the water and with officials having approved a plan for reaching emission limits set by the Climate Leadership and Community Protection Act (CLCPA). (See New York Set to Start Building Big in 2022.)

“With this investment, New York will lead the nation on offshore wind production, creating green jobs for New Yorkers and powering our clean energy future,” Hochul said.

New York will invest up to $500 million in the ports, manufacturing and supply chain infrastructure needed to advance its OSW industry, with state agencies and its Green Bank leveraging private capital to deliver more than $2 billion in economic activity while creating more than 2,000 green jobs.

Hochul also said that the New York Energy Research and Development Authority (NYSERDA) will launch its next OSW procurement this year, resulting in at least 2 GW of new projects. NYSERDA will pick up the pace on OSW transmission planning and conduct a study to identify strategic OSW cable corridors and key points of interconnection to the grid.

Anbaric Development Partners lauded the governor’s recognition of the need for a planned transmission system to deliver offshore wind power.

“Studies have continuously demonstrated that transmission planned to accommodate and integrate significant amounts of offshore wind is a much more cost-effective, environmentally sound and electrically reliable approach to integrating clean electricity,” Janice Fuller, Anbaric president for the mid-Atlantic region, said in a statement.

New York also will work to electrify 2 million homes or make them electrification-ready by 2030, and new legislation will seek to ensure that all new building construction reaches zero-emissions by 2027, Hochul said.

Building emissions cause more than one third of New York’s climate pollution, and the new plan will help more than 800,000 low-to-moderate income households secure clean energy upgrades.

“Gov. Hochul’s announcement of $500 million in investments for offshore wind, on the eve of the state’s third solicitation and the upcoming NY Bight Lease sale, is a win for New York communities, workers, businesses and our climate,” Allison Considine, senior campaign representative for Sierra Club, said in a statement. “This significant investment, when paired with commitments to double battery storage to 6 GW by 2030, planning to phase out dirty peaker plants and achieve 2 million all-electric homes by 2030, demonstrates that New York will continue to lead the nation in transitioning from fossil fuels to zero-emission electricity.”

The state-level move on building emissions follows action last month by the New York City Council, which voted to ban the use of natural gas for heating or hot water in new construction or renovations beginning in 2024. (See NYC to Ban Natural Gas in New Buildings Beginning 2024.)

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Santee Cooper Joins SEEM

South Carolina state-owned electric and water utility South Carolina Public Service Authority (Santee Cooper) has agreed to join the Southeast Energy Exchange Market (SEEM), the company said Thursday.

The move adds Santee Cooper to the list of “founding members” of SEEM, which comprises nearly 20 utilities across 11 states including Southern Co., Dominion Energy South Carolina, LG&E and KU, the Tennessee Valley Authority and Duke Energy. SEEM’s members said last month they plan to launch the market in the third quarter this year. (See FERC Rejects SEEM Opponents’ Rehearing Requests.)

Santee Cooper’s embrace of SEEM shows the support the concept has gained in the energy industry since its supporters submitted the proposed agreement to FERC last February. Proponents say the planned expansion of bilateral trading across the Southeast will reduce trading friction through the introduction of automation, eliminating transmission rate pancaking and allowing 15-minute energy transactions, while also promoting the integration of renewable resources.

In a press release, Santee Cooper Deputy CEO Charlie Duckworth said the utility is “excited by the opportunities SEEM will offer our customers, including better capability for integrating renewables and savings from lower fuel costs and improved efficiencies.”

The SEEM agreement took effect in October after FERC — which at the time had just four commissioners after the departure of Neil Chatterjee — split 2-2 over whether to approve the measure. Because it had been more than 60 days since supporters’ response to FERC’s last deficiency letter, the measure automatically became enforceable under Section 205 of the Federal Power Act. (See SEEM to Move Ahead, Minus FERC Approval.)

Since then the commission has approved revisions to four of the participating utilities’ tariffs implementing the special transmission service used to deliver the market’s energy transactions. (See FERC Accepts Key Tariff Revisions to SEEM.) Members have also submitted further changes to the commission that would implement a series of “transparency enhancements” to the market. (See SEEM Members Embrace Market Changes.)

Santee Cooper is South Carolina’s largest power provider and the ultimate source of electricity for 2 million people across the state. The utility’s fate has been up in the air in recent years after losing billions in 2017 on a failed project to expand a nuclear power plant, which led the state to put it up for sale in 2019. Florida-based NextEra Energy put in the highest bid but withdrew its offer last April when it became clear that South Carolina lawmakers lacked the votes to approve the sale because of concerns that it would lead to layoffs and higher electric rates.

Instead of selling the utility, lawmakers voted through a package of measures that included removing nine of the 10 members of the utility’s board of directors and restricting severance pay for any terminated executives. The changes also gave state regulators more power over Santee Cooper by allowing them to review its future generation plans and power forecasts and to require public hearings and government oversight ahead of future rate increases.

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NEPOOL PC Approves Tariff Changes for Aggregated DERs

BOSTON — The NEPOOL Participants Committee on Thursday approved ISO-NE’s proposed tariff changes aimed at allowing distributed energy resource aggregations (DERA) to participate in the RTO’s markets. 

The changes, intended to comply with FERC Order 2222, would create two new market participation models for DERAs and tweak five existing ones. 

The proposal sets a minimum size of 100 kW for DERAs in all of the models and includes an opt-in provision which prohibits aggregation bids from distribution companies below 4 million MWh in annual sales unless the relevant retail regulatory authority signs off.

Participation models for DERAs (NEPOOL) Content.jpgISO-NE’s Order 2222 compliance filing would create two new market participation models for DERAs and tweak five existing ones.  | NEPOOL

It creates a four-stage registration process to allow a distribution utility to confirm the necessary capabilities to participate in a DERA. Other changes would amend Forward Capacity Market rules to allow DERAs to take part. 

The changes to the FCM would go into effect in the fourth quarter of 2022, and the others not until 2026. 

Advanced Energy Economy (AEE), which argued that the proposal fails to remove significant barriers to market participation for DERAs, submitted seven amendments while it was under consideration in the Markets Committee. But those were voted down and the group declined to bring the amendments to a vote again for this week’s PC meeting. (See Stakeholders Approve ISO-NE Order 2222 Compliance Plan)

AEE declined to comment on whether it will  advocate for changes once the proposal is under consideration by FERC. 

ISO-NE has until Feb. 2 to file the proposal. 

Billing, FCM Settlement Changes

The PC also voted Thursday on several other items, including changes to the way ISO-NE handles requests for billing adjustments. The requests will now have to be submitted via the AskISO system, instead of by email, because cybersecurity measures have “in some cases hampered receipt” of the requests, according to the RTO. 

The PC also approved a change to convert certain credits and charges associated with the FCM from a monthly settlement to a daily settlement. The proposal will reduce financial assurance for load serving entities and accelerate payments to resource providers, the RTO said. 

Consent agenda

The committee also approved: 

  • changes to Planning Procedure 10 (Planning Procedure to Support the Forward Capacity Market), including conforming changes for ER21-640, related to qualification of non-commercial resources in annual reconfiguration auctions, and ER19-343, related to the modeling of peaking generation in reliability reviews;
  • changes to Operating Procedure 16K (Transmission System Data – Submission of Short Circuit Data), part of a biennial review with minor updates to process flow diagram; and
  • changes to Operating Procedure 3 (Transmission Outage Scheduling), part of biennial review with minor edits and grammatical revisions.
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Youngkin Taps Trump’s Former EPA Chief to Head Virginia DNR

Andrew Wheeler, the former coal industry lobbyist who led EPA under former President Donald Trump, is now slated to head Virginia’s Department of Natural Resources.

Governor-elect Glenn Youngkin (R) nominated Wheeler to the post Wednesday, setting off a storm of criticism from Virginia Democrats and environmental advocates.

U.S. Rep. Don Beyer (D-Va.) tweeted that “Wheeler is one of the worst people the governor-elect could have chosen for the job.”

“Putting an anti-environment ideologue in this important position would be a far cry from the kind of consensus-based, pragmatic leadership the governor-elect promised,” Beyer said in an attached statement.

“This nomination is extremely disappointing,” seconded Sarah Francisco, director of the Southern Environmental Law Center’s Virginia office. “As a former head of EPA in the Trump administration and former coal industry lobbyist, Mr. Wheeler has a record of weakening fundamental safeguards for clean water and healthy air and opposing common-sense efforts to tackle climate change.”

Youngkin’s announcement of the nomination praised Wheeler’s “extensive experience and passion” and his dedication “to advancing sound environmental policies.”

Gov-elect Glenn Youngkin (Youngkin for Governor) FI.jpgGov.-elect Glenn Youngkin | Youngkin for Governor

Wheeler shares “my vision in finding new ways to innovate and use our natural resources to provide Virginia with a stable, dependable and growing power supply that will meet Virginia’s power demands without passing the costs on to the consumer,” Youngkin said.

Following his victory over Democrat Terry McAuliffe in November, Youngkin named Wheeler as part of his transition team, specifically as part of the Natural and Historic Resources group.

Under Virginia’s constitution, both houses of the General Assembly must confirm Wheeler and other potential cabinet members. While Wheeler may face little opposition in the Republican-led House of Delegates, he could hit a wall in the Senate, where Democrats still hold a 21-19 advantage.

Citing Wheeler’s “well established record from his time in the Trump administration,” Harry Godfrey, executive director of Virginia Advanced Energy Economy, said “it is vital that the Senate consider that record and determine whether it aligns with the policy direction that the General Assembly has established in recent years,” such as the Virginia Clean Economy Act (VCEA).

Sen. Scott Surovell (D) told the Virginia Mercury that while Senate Democrats have not discussed the nomination, “I think a lot of our members are going to have very serious concerns.”

Surovell also cautioned that “any Republican member who’s in any kind of competitive suburban seat would really need to think twice about voting for someone like [Wheeler] given where Virginia’s been leading on environmental policy.”

Wheeler’s nomination could be the first test of the Senate’s ability to push back on Youngkin’s efforts to slow the state’s progress toward the VCEA’s goal of a 100% clean energy supply by 2050. For example, the governor-elect has vowed to take Virginia out of the Regional Greenhouse Gas Initiative (RGGI) via an executive order. The initiative is a multistate carbon market aimed at cutting greenhouse gas emissions across 11 New England and Mid-Atlantic states.

A General Assembly vote approved the state’s membership in RGGI; any move by Youngkin to rescind that approval by executive order could also spark opposition. Similarly, the Senate is seen as a firewall to forestall any attempt to repeal the VCEA.

Wheeler’s Record

Wheeler’s environmental record goes back to his work as chief counsel for Sen. Jim Inhofe (R-Okla.), an outspoken climate change denier, from 1995 to 1997. He also worked a lobbyist for the coal industry from 2009 to 2017 at the law firm of Faegre Baker Daniels (now Faegre Drinker Biddle & Reath).

In 2018, when he was the EPA’s acting administrator, Wheeler drew criticism for discounting the findings of the National Climate Assessment, begun during the Obama administration, claiming the report “pushed” a worst-case scenario. During his confirmation hearings to be the official administrator in 2019, he skirted repeated questions from Democratic senators on his views on climate change.

When pressed by Sen. Bernie Sanders (I-Vt.), Wheeler called climate change “a global issue that must be addressed globally,” but not “the greatest crisis. … I consider it a huge issue that has to be addressed globally.” (See Dems Press Wheeler on Climate at Confirmation Hearing.)

Once confirmed, Wheeler weakened or rolled back a number of former President Barack Obama’s key environmental initiatives, such as the Clean Power Plan, aimed at reducing carbon emissions from power plants, and regulations requiring coal plants to clean up coal ash ponds. Working with the Department of Transportation, Wheeler’s EPA in 2020 also froze fuel efficiency standards to a fleet average of 32 mpg by 2026.

Current EPA Administrator Michael Regan recently issued new rules, resetting the target for 40 mpg by 2026. (See EPA Rules Will Slash Emissions, Rev up EV Market by 2026.)

‘Not the Right Fit for Virginia’

The Virginia chapter of the Sierra Club called on Youngkin to withdraw the nomination.

The “reckless” nomination “is proof that Youngkin is willing to sell out our communities and our clean air and water for corporate profits,” said Kate West, chapter head. “In lieu of withdrawal, Democrats must use their [Senate] majority to prevent one of the most dangerous appointments in our state’s history.”

Del. Dan Helmer (D) tweeted that Wheeler’s record at EPA is “disqualifying,” vowing to “fight this nomination tooth and nail.”

“Anyone with [Wheeler’s] record is simply not the right fit for Virginia,” said Kim Jemaine, Virginia director of the Chesapeake Climate Action Network Action Fund. “During his extensive career as a henchman for the coal industry and the Trump administration, Wheeler has made it clear that he is willing to risk the health and safety of Virginians in order to serve the interests of bad actors. We should take this record at face value.”

Youngkin’s nomination of Michael Rolband to head the Department of Environmental Quality, on the other hand, went without comment. Rolband appears to have a long history as an advocate for wetlands preservation and restoration. He founded Wetlands Studies and Solutions, an environmental and cultural resources analysis firm, as well as the Resources Protection Group, a wetlands conservation nonprofit.

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Dixie Fire Finding Inopportune for PG&E

The finding by state investigators this week that a Pacific Gas and Electric line sparked last year’s immense Dixie Fire arrived at an awkward time for the beleaguered utility, which is hoping to be released from five years of federal probation later this month.

The California Department of Forestry and Fire Protection said Tuesday its investigation had found that a tree falling onto a PG&E distribution line ignited the nearly 1-million-acre wildfire, 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 news release.

The finding was not a surprise. PG&E said soon after the fire began in mid-July that its line may have sparked the fire that burned for more than three months across the northern Sierra Nevada. (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 Tuesday. “This tree was one of more than 8 million trees within strike distance to PG&E lines.”

Cal Fire rendered its conclusion one day after federal Judge William Alsup said in a hearing that he would consider extending PG&E’s probation beyond its current end date of Jan. 25 if federal prosecutors ask him to. The U.S. Attorney’s Office is expected to decide this week whether to file such a request, and Alsup scheduled a hearing on the matter for Monday.

Cal Fire’s findings regarding the Dixie Fire could weigh into a decision by the judge, who has been one of PG&E’s harshest critics.

In November, Alsup found that PG&E had likely violated its probation for felonies related to the 2010 San Bruno gas explosion by starting 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. (See PG&E Likely Violated Probation, Judge Finds.)

County prosecutors have filed charges against PG&E in both cases, while the utility has denied it was criminally liable for either fire.

Also 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.  

Fires started by PG&E equipment that failed or was struck by trees included the 2018 Camp Fire, which destroyed the town of Paradise and killed at least 84 people.

“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,” the monitor wrote.

Its reviews of PG&E safety practices showed the utility had missed thousands of dangerous trees near its lines and failed to detect worn or broken equipment. 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 acres 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 timeframe for the work but has plans to underground just 66 miles of lines in 2021 and a total of 327 miles over the next three years, the monitor said.

Even if 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.

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FERC Accepts ISO-NE Request to Terminate Killingly CSO

FERC on Monday accepted ISO-NE’s request to yank the capacity supply obligation for the Killingly Energy Center in eastern Connecticut, dealing another near-fatal blow to the contentious 650-MW natural gas plant under development (ER22-355).

The RTO has said that Killingly, which secured a CSO for the 2022/2023 capacity period, has failed to meet developmental milestones and is on track to not be in commercial operation by the required date of June 1, 2024, two years after the start of that period. Developers have up to two years to find other resources to meet their CSO obligations if they themselves cannot.

Developer NTE Energy disagreed with ISO-NE’s claims about delays on the project, saying they were out of its control because of factors including legal challenges and the COVID-19 pandemic. The company claimed in November that financing is “imminent” and challenged what it called “an incorrect assumption” by the RTO that led to a “premature” decision. (See ISO-NE Seeks to Terminate CSO for Conn. Power Plant.)

But in an order issued Monday, FERC sided with ISO-NE, saying it was “persuaded by the evidence” presented that Killingly will not achieve critical milestones by 2024. After consulting with NTE, which it did in several meetings over two months, the RTO has the right to terminate the CSO, FERC said.

As a result of FERC’s ruling, the company will lose its CSO, forfeit financial assurance associated with the terminated megawatts and no longer be eligible for the next Forward Capacity Auction in early February.

NTE, Opponents React

NTE says it’s not giving up on the project.

“We are very disappointed and do not agree with FERC’s decision,” the company’s managing director, Tim Eves, said in a statement. “The Killingly Energy Center is important for grid reliability, and we will continue to work to be the bridge for the region’s carbon-free future.”

But the plant’s future is cloudy. The company itself has said in filings that FERC’s approval of ISO-NE decision would cause it “irreparable” damage and lose it hundreds of millions of dollars of revenue.

Environmental groups in Connecticut, which have opposed Killingly and sued over the project in a case that was ultimately decided by the state Supreme Court, celebrated this week at the latest dimming of the project’s future prospects.

“It was the outcome we hoped for, and we’re happy,” said Samantha Dynowski, director of the Connecticut chapter of the Sierra Club.

She said the plant ever being built appears “very unlikely” without a CSO.

“In the face of [ISO-NE] not wanting them and Gov. [Ned] Lamont saying he doesn’t want the plant … they’d really just be forcing themselves on a market that doesn’t want them here,” Dynowski said.

The order has broader implications for ISO-NE, and the events leading to it should spur action by the RTO, said Dan Dolan, president of the New England Power Generators Association.

“Moving forward, more needs to be done to ensure that new facilities only offer into the market when they are ready to come in on time,” Dolan said in an email to RTO Insider. “Market reforms should include proposals like escalating penalties for delays. This will help make continued improvements to provide reliability value for New England consumers and competitive revenue opportunities to those facilities providing the reliability services.”

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PG&E Building ‘Remote Grids’ in Fire-prone Areas

Pacific Gas and Electric plans to build more standalone “remote grids” in California this year, allowing the utility to remove distribution lines serving small groups of isolated customers as a way to reduce wildfire danger.

After finishing its first remote grid project in Briceburg, Calif., last year, PG&E said it was setting a target of having up to 20 remote grids up and running by the end of this year.

And community choice aggregators are partnering with PG&E on some of the projects. Sonoma Clean Power, which serves Sonoma and Mendocino counties, is hoping to have its first remote grid project completed within a year.

Sonoma Clean Power CEO Geof Syphers said the remote grids could increase the use of clean energy, decrease wildfire risk and reduce costs to electric ratepayers.

“It could be a triple win,” Syphers told NetZero Insider.

Solar, Storage and Backup

PG&E decided to build the Briceburg remote grid after the 2019 Briceburg Fire destroyed a distribution line serving five customers. The power line ran across rugged terrain in a high fire-threat area near Yosemite National Park.

The Briceburg remote grid consists of solar panels, battery storage and backup propane generators. It serves two homes, a visitor center, and telecommunications and transportation facilities.

The remote grid uses ground-mounted and container-mounted solar panels provided by BoxPower, a Grass Valley-based company. The containerized microgrid system may streamline development of future remote grids at similar sites, according to a release.

The remote grid includes a fire suppression system, and PG&E and BoxPower can monitor and control the grid via satellite.

The system is expected to provide up to 89% renewable energy per year.

“This hybrid renewable option reliably powers five customers without the need to rebuild the overhead line, and the remote grid is intended to meet customer needs at lower lifetime costs and a significantly lower risk of fire,” PG&E spokesperson Paul Doherty said in an email.

PG&E said there are hundreds of potential sites for remote grids in its service territory. The company is evaluating high fire-threat areas in El Dorado, Mariposa, Sonoma, Tulare and Tehama counties.

Lessons learned from Briceburg and other early projects will guide PG&E’s remote-grid expansion, the company said.

PG&E plans to provide an update on the remote grid program next month when the company files its 2022 Wildfire Mitigation Plan.

CCA Involvement

Community choice aggregators are helping PG&E with remote grid projects by reaching out to customers who might be good candidates for joining a remote grid.

Syphers at Sonoma Clean Power said the outreach includes a discussion on how to maximize the use of renewable energy. Thus far, one customer has agreed to a 100% renewable system, he said.

The trade-off for 100% renewable is the potential for reduced reliability, Syphers said. But he noted that customers might already be experiencing periods of public safety power shut offs while overhead distribution lines stay in place.

Syphers said a typical remote grid site would include one to three customers at the end of a power line running through a high fire-threat area.

Electric use for a remote grid should be on a residential scale, he said, although some non-residential uses such as agricultural water pumping could be accommodated.

It’s ultimately up to PG&E to decide whether a remote grid makes sense for a particular site, Syphers said. One factor is how the cost of a remote grid compares to the cost of hardening an overhead distribution line in a high fire-threat area, which could involve replacing bare overhead conductor with covered conductor, installing sturdier poles or moving the line underground.

“This is an opportunity to just be smarter about how we’re using ratepayer dollars,” Syphers said.

Sonoma Clean Power’s remote-grid planning also includes a “top-to-bottom” energy-efficiency retrofit.

Syphers said he could envision larger remote grids that include seven to 10 customers, but he noted that all customers must be willing participants.

“It could grow as we learn more,” he said.

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MISO Makes 2nd Plea for Time on ROE Refunds

MISO has made another attempt to coax more time from FERC to calculate refunds to transmission customers over the commission’s ever-changing return on equity percentage.

The RTO has now asked for an extension until May 31 to complete the refunds (EL14-12-004).

The grid operator previously requested a June 30 deadline to determine refund amounts; FERC granted a delay until Feb. 28 from its original Sept. 23, 2021, deadline to calculate the reimbursements. (See MISO, TOs: More Time Needed for ROE Refunds.)

MISO said it has good cause to support a spring deadline, saying the “overall resettlement task remains unchanged” since it first requested an extension. The RTO said it and its transmission owners have completed resettlements from 2013 to 2019, but said the remaining refunds require a more complex calculation that relies on forward-looking transmission rates and true-up mechanisms.

The grid operator said it expects to crunch numbers through April, with transactions to take place in May. MISO Senior Manager of Transmission Settlements Christina Drake said it remains “infeasible to implement all of the directed refunds within the timeframe set forth by the commission’s orders.” It promised the refunds will include interest at FERC-approved rates.

MISO said as an example, 2020’s refunds involve 103 transmission owners and “all charges made under related tariff schedules and attachments that use those parties’ ROE, including the systemwide average rate for through-and-out service.”

The RTO’s extensive refund calculations stem from a return on equity that FERC changed several times over a handful of years as it tried to nail down an appropriate baseline for investors backing transmission projects.

The commission in 2020 enacted a 10.02% ROE for transmission rates effective Sept. 28, 2016, superseding the 9.88% and 10.32% ROEs approved in 2019 and 2016, respectively. Those figures were at different times intended to replace the 12.38% ROE established in 2002, which FERC deemed excessive almost a decade ago. In all, MISO TOs must pay refunds for the period of November 2013 to February 2015 and September 28, 2016, to December 23, 2020. (See FERC Ups MISO TO ROE, Reverses Stance on Models.)