Texas Public Utility Commissioner Shelly Botkin resigned Monday, leaving the three-person body with just one member.
The PUC announced Botkin’s departure in a one-sentence statement saying she had “resigned her role … effective immediately.”
Botkin’s resignation leaves only Chair Arthur D’Andrea on the PUC. Former Chair DeAnn Walker resigned last week after taking heat from lawmakers over the PUC’s response to the February blackouts that left millions of Texans without power during a cold snap. (See PUCT’s Walker Steps Down from Commission.)
The Texas PUC is down to one commissioner. | PUCT
Botkin was appointed to the commission by Gov. Greg Abbott in 2018 and reappointed in 2019 to a term that would have expired in 2025. Previously, she handled government relations and communications for Texas PUC’s Botkin Applies Life Lessons to Work.)
At her last PUC open meeting on March 5, Botkin said she would be taking Walker’s position on SPP’s Regional State Committee. However, something apparently changed over the weekend and, on Monday, she surprised staff with her resignation.
Transmission and reliability consultant Alison Silverstein told RTO Insider that Botkin’s time with ERCOT has invited conflict-of-interest perceptions as state officials sort through the cause of the outages, which claimed the job of ERCOT CEO Bill Magness and prompted multiple resignations from the ISO’s board. (See ERCOT Cuts Ties with Magness.)
“Real or not, the appearance of bias cannot be overcome by [Botkin’s] deep industry expertise and personal integrity, and this issue is too important to be compromised by potentially tainted decisions from Texas’ lead regulatory agency,” Silverstein said.
Under the PUC’s governing statute, the commission is able to convene meetings with just one commissioner. That happened in 2001, when Brett Perlman was left by himself after Judy Walsh cycled off the PUC and Pat Wood was nominated for the FERC chairmanship. Perlman conducted at least one meeting by himself.
The commission’s next open meeting is scheduled for Thursday.
During its last meeting, the PUC declined to act on the ERCOT Independent Market Monitor’s recommendation to reprice $16 billion worth of emergency market transactions, saying the unintended consequences could be disastrous to a different set of market participants. (See Texas PUC Won’t Reprice $16B Error.)
Lt. Gov. Dan Patrick responded Monday by calling for the PUC and ERCOT to follow the Monitor’s recommendations. He said the PUC had “declined” to exercise its authority and follow the Monitor’s recommendation.
“Correcting this $16 billion error will require an adjustment, but it is the right thing to do,” he said. “It will ultimately benefit consumers and is one important step we can take now to begin to fix what went wrong in the storm.”
NERC and the regional entities pushed back last week on FERC’s proposal to shorten the time between the organization’s performance assessments from five years to three, warning that the change would force it to “redirect staff resources from … issues facing the” bulk power system (RM21-12).
FERC pitched the move in a Notice of Proposed Rulemaking issued in January under the chairmanship of Commissioner James Danly, saying a quicker turnaround would “provide better continuity” in its oversight of the ERO Enterprise and its ability to identify potential performance improvements in a more timely fashion. The NOPR was issued alongside an order for NERC to audit the compliance monitoring and enforcement programs of all REs by June 2023. (See FERC Orders Audits of All REs by 2023.)
Also included in the NOPR was a proposal to allow FERC to request additional information beyond the statutory requirements of the performance assessment; NERC would have to honor any such requests submitted at least 90 days before the assessment’s publication date. The NOPR would also require the ERO to solicit recommendations by industry stakeholders for improvements to its “operations, activities, oversight and procedures.” Any stakeholder comments received would be included in the assessment along with NERC’s responses.
Objections to Compressed Time Frame
In their response, NERC and the REs recognized that the commission’s proposals appeared driven by “effective and efficient communication, coordination, and feedback objectives.” But they said they nevertheless found flaws with each proposal that, taken together, would “place a burden on ERO Enterprise staff … that would outweigh any potential benefits.”
In this regard the enterprise is following a cue provided at FERC’s January meeting by Commissioners Neil Chatterjee and Richard Glick, now the chair. In a joint statement, the two asked specifically for feedback on “potential burdens” that the proposal could impose on the organizations; in his oral comments Chatterjee further expressed concern “that the additional layers of administrative process … may miss the mark.”
The enterprise’s response to FERC echoes this fear, claiming that because of the need to coordinate with the REs, incorporate stakeholder feedback and gain approval from NERC’s Board of Trustees, “a three-year performance assessment cycle would … effectively [require] NERC to prepare an assessment every two years.” In addition, a more restricted time frame “might not enable … a comprehensive review of the myriad of activities and topics” required by the performance assessment.
NERC also objected to the commission’s suggestion that the current schedule does not permit it to conduct active oversight of the enterprise. The organization pointed out that commission staff are “aware of and involved in” the activities of the enterprise at many levels, from standards development teams, to the quarterly meetings of the REs’ boards of directors and of NERC’s board and Member Representatives Committee.
The enterprise also submits Annual Business Plan and Budget filings to FERC and collaborates with commission staff on their drafting, along with submitting proposed reliability standards for approval and incorporating changes requested by the commission, the organizations noted. These “constant communication and feedback loops” could be disrupted by a shorter assessment time frame that distracts NERC staff from collaboration efforts, making the proposal not just unnecessary but potentially harmful, they said.
ERO Open to Other Proposals
FERC’s proposal of a mandatory solicitation of stakeholder comments by NERC met with similar objections. The organization pointed out that not only does it post drafts of the assessments for public comment three months prior to their submission, it also “provides extensive opportunities for stakeholder feedback” on an ongoing basis, “including areas for improvement.” Interested parties can provide their comments by participating in NERC’s committees or through the MRC.
“The NOPR does not explain the basis of its proposal for a separate stakeholder comment process discrete from all other existing robust feedback mechanisms,” the ERO Enterprise said. However, NERC did leave the door open for compromise by suggesting that it could start the comment period for the assessment earlier or provide stakeholders more time to comment.
NERC also signaled its willingness to accommodate the commission’s proposal to require additional specific information ahead of the assessment’s publication, admitting that “it could help illuminate particular areas of interest.” Although the organization maintained that 90 days was not sufficient notice, it suggested six months would give its staff enough time to incorporate the commission’s requests into the document.
Finally, NERC and the REs pointed out that FERC had not indicated when it hoped for the proposed changes to take place and that nearly two years have already passed since the ERO’s last performance assessment. (See NERC Wins Another 5 Years as ERO.) Noting that many scheduling aspects of the next assessment — currently scheduled for 2024 — have already been set, the enterprise strongly urged FERC to delay any changes until after it is finished.
New Jersey is pushing to cut carbon emissions from the mammoth Port of New York and New Jersey, with an infusion of more than $35.5 million to electrify cargo transportation and cut emissions in environmental justice areas.
Gov. Phil Murphy on Feb. 16 announced grants totaling $19.5 million for the purchase of electric cargo equipment and medium- and heavy-duty trucks to reduce carbon and other emissions in or around ports. The grants are part of a $100 million fund to promote electric vehicle use with funds from the state’s Volkswagen settlement.
The plan followed the Murphy administration’s announcement in January of a $16 million incentive program designed to cut emissions in two environmental justice communities close to ports. The state will award vouchers of between $25,000 and $100,000 to fund the purchase of electric medium- and heavy-duty zero-emission trucks within 10 miles of Newark, an area that includes most of the Port of New York and New Jersey, and Camden, home to the far smaller South Jersey Port Corp. (SJPC).
Emissions from the Port of New York and New Jersey, the largest port on the East Coast, have long been a concern for Newark area residents and environmental groups, reflecting a dynamic that has played out at ports across the country, especially in California. The dramatic rise in cargo volumes through many U.S. ports in recent years has increased truck and vessel traffic, raising emissions that impact nearby communities. That has forced ports to try to pursue efforts to cut pollution and protect area residents without impairing the cargo flow that is vital to the economy.
In the Port of New York and New Jersey, that dynamic is felt most strongly in New Jersey, which hosts the four largest of the port’s six container terminals. Together those four handle 90% of the port’s containerized cargo.
Murphy’s initiatives reflect his drive to put the state on track for 100% clean energy by 2050, in part by reducing energy consumption and emissions in transportation, which accounts for 42% of greenhouse gas emissions in New Jersey, according to the New Jersey Department of Environmental Protection (DEP).
As part of that drive, DEP said it plans to introduce rules in the spring that will require truck manufacturers to sell an increasing number of EVs in the state beginning in 2025. Modeled after California regulations, the proposed rules would also require truck fleet owners to report their level of EV use so that the state can collect data for future rules, which are expected to include EV purchase requirements for the fleets.
The DEP also said that in the long term, it will consider rules that would require the use of zero-emissions cargo handling equipment.
“We have been on this very slow crawl of the evolution to electric, and I think we’re almost reaching the top of our mountain,” said Bethann Rooney, deputy port director for the Port Authority of New York and New Jersey (PANYNJ). “Things are coming together. We’re on the brink of being able to really make some important changes in short order.”
Faster Transition to EVs
The $19.5 million in grants will fund a significant increase in the use of EVs in the port, where electric yard tractors are scarce and just three electric drayage trucks — tractor trailers that move containers in or out of the port — are in use, according to the PANYNJ.
But the effort also highlights how far the state has yet to go. The funding will put an additional 16 electric drayage trucks in the port, a fraction of the 9,000 diesel trucks that serve the port each month.
The funds allocated for the port include:
$850,000 to PANYNJ for a mobile electric crane;
$2.3 million to buy container moving “straddle carriers” for two port terminals;
$3.5 million for truckers and warehouse operators to buy 10 container-handling vehicles or yard tractors;
$4.8 million for trucking company International Motor Freight of Newark to buy 15 electric trucks; and
$6.6 million to fund the acquisition of 23 yard tractors for use at the SJPC, which handles non-containerized cargo such as steel slabs, cocoa beans and wind turbine equipment.
Growth in Cargo and Emissions
The challenge facing the northern port was reflected in a PANYNJ report released in December called the Multi-Facility Emissions Inventory, which showed that in 2019, the port released 709,069 tons of GHGs. That was an increase of 2% over the 2018 figure, as cargo volumes increased by 4%. The report said heavy-duty vehicles were the largest producer of GHGs, emitting about twice as many as the next category, ocean going vessels. Third ranked was port cargo-handling equipment.
An unrelated report on mobile emissions in the Newark area, prepared for the New Jersey Environmental Justice Alliance, found that the highest transportation emissions burden occurred in “locations close to high density truck and bus routes and locations close to port facilities and rail yards.” The largest impact on “PM2.5 [particulate matter of 2.5 microns or less in width], black carbon and NOx” emissions comes from “non-roadway sources, particularly locomotives and port operations,” the report, which was released in November, concluded.
Kim Gaddy, environmental justice organizer for Clean Water Action New Jersey and a member of the Coalition for Healthy Ports NY NJ, welcomed Murphy’s EV funding. She called on all government agencies to help the push toward zero-emission vehicles (ZEVs).
“Gradual, incremental steps just won’t do,” she said in a press statement after Murphy’s announcement. “All of the vehicles and equipment serving the Newark port” must be electrified, she said.
Removing Dirty Trucks
With 14,000 truck trips on a typical day, the PANYNJ for more than a decade has sought to reduce emissions by offering incentives — now totaling more than $30 million — to trucking companies to replace older diesel trucks with newer, cleaner models.
In 2016, the authority crafted — and then dropped — a plan to prohibit all trucks with engines made in 2007 or earlier. Instead, PANYNJ continued the incentive program, which now awards grants of $25,000 to truckers that replace an aging truck with one using a 2014 model engine or newer.
Even as older trucks are removed from the port, however, emissions have grown, though far more slowly than cargo volumes, according to the Multi-Facility Emissions Inventory. From 2006 to 2019, emissions grew by 3%, and cargo volumes increased by 47%.
New Jersey’s efforts follow those in California, where severe air pollution has for years triggered aggressive measures to reduce truck emissions in the ports of Los Angeles and Long Beach. Los Angeles, for example, said it already has 29 ZEVs working in the port.
Both Los Angeles and Long Beach prohibit trucks older than 2014 from joining their truck fleets. And the California Air Resources Board in 2020 adopted a rule — like the one now under consideration in New Jersey — that requires truck makers to sell an increasing number of zero-emission trucks in the state.
In New Jersey-New York, the transition to electric trucks is still nascent. The first test of an EV drayage trip took place in August 2019. But Gail Toth, executive director of the New Jersey Motor Truck Association, said truckers balk at the limited range of electric trucks (about 250 miles) with price tags about twice as high as the $150,000 cost of a diesel truck, along with the cost of building a charging station.
Red Hook Container Terminals expects to begin operating 10 electric yard tractors, or container handling vehicles, in March. | Hudson County Motors
The implementation of electric yard tractors is growing more rapidly, however. Trucking company Best Transportation in 2019 ordered two electric yard tractors. And Red Hook Container Terminals expects in March to begin operating 10 electric yard tractors, purchased with an earlier round of VW settlement funding, said James Sherman, vice president of Climate Change Mitigation Technologies, which helped create the project.
Sherman believes that Murphy’s funding programs could now put New Jersey at the forefront of the shift to EVs.
“New Jersey can be the second largest battery electric truck market in the United States” after California, he said.
A proposed competitive clean energy solicitation in New Hampshire could spur offshore wind construction in the Gulf of Maine by 2026, state Sen. David Watters (D) said Monday.
Watters cosponsored a bill (SB 151) that would establish a state procurement plan for 800 MW of renewable energy, with at least 600 MW dedicated to OSW capacity.
The 800-MW solicitation is “about right” for New Hampshire and the capacity of utilities to use the electricity, Watters said in a Senate Energy and Natural Resources committee hearing on the bill. Under the bill’s procurement timeline, the state would issue a solicitation by June 30, 2022, with the expectation that electric distribution companies would enter 15- to 30-year contracts for the power by June 30, 2023.
The proposed size and timing of the solicitation, however, seemed large and aggressive to Robert Furino, director of energy contracts at Unitil subsidiary Unitil Service.
“If the state were to sponsor these contracts, and we were to sign 600 MW to 800 MW of offshore wind, for example, our share would lead to covering 20% to 30% of our peak requirements and 40% to close to 60% of our annual energy requirements, based on 2019 actual consumption of our customer base,” Furino said in his hearing testimony.
Unitil Service has electric customers in southeastern New Hampshire, which has about 18 miles of Atlantic coastline.
Despite his hesitation about the size of the procurement, Furino said a state-sponsored solicitation is a necessary incentive for the OSW market.
“I don’t see [OSW investments] coming without contracts,” he said. “There’s some onshore wind that’s been contracted just by the market, and I don’t know that you would see that forthcoming in an offshore market.”
The bill allows for joint solicitations with other New England states, a measure Furino said makes sense for a state the size of New Hampshire.
“We were involved in one multistate procurement [with] Connecticut, Massachusetts and Rhode Island,” he said. “I do think it would reduce the valuation burden and hopefully increase the market interest.”
Generator Concerns
The New England Power Generators Association opposes long-term contracts that single out and incentivize specific resources, Daniel Collins, NEPGA director of government affairs, said in his testimony. The group represents electric power generators that compete in ISO-NE wholesale markets.
The contracts proposed in the bill would distort market pricing and undermine the commercial viability of competitive resources that do not receive a guaranteed revenue stream outside the markets, he said.
Market-based solutions, he added, offer a “better path” to meeting the state’s energy goals than putting the cost and investments of long-term contracts onto ratepayers.
Workforce Solutions
The state’s solicitations, as designed in the bill, would require bidders to prepare plans for project labor agreements and use of skilled labor, including opportunities for apprenticeship training or workforce development recognized by the state.
The BlueGreen Alliance supports those labor and workforce development measures, according to Rebecca Newberry, Northeast regional program manager for the alliance.
“Apprenticeship utilization can reduce the risk of cost overruns for substandard work, while project labor agreements provide comprehensive guidance for large projects,” Newberry said in her testimony.
The alliance, she said, recommends adding local hire criteria to bid requirements to help create jobs and generate economic activities. In addition, language in the bill should place priority on “projects that will source a high percentage of components from U.S.-based manufacturers,” she said.
Minnesota Rep. Todd Lippert (DFL) knows the state’s divided political environment could halt significant climate legislation, but he is pushing forward anyway because he says his Northfield community has seen the impact of climate change firsthand.
“Flooding is an intensifying concern,” says Lippert, who also serves the community as a minister. “Northfield is just one example. In just the last 10 years, the Cannon River has damaged the community with three 500-year floods.”
Lippert is chief author of the “100% Soil Healthy Farming” bill, designed to “protect soil and water, save farmers money and help us meet our climate goals as a state.”
The bill (HF 701), spearheaded by the Land Stewardship Project (LSP), seeks to have 50% of the state’s farmers implementing soil healthy practices by 2030 and 100% of farmers using such practices on some of their fields by 2035. It also sets a goal by 2040 for 100% of the state’s grazable and tillable acres utilizing such practices.
Luke Peterson, a Dawson, Minnesota, farmer and LSP member, endorsed the bill at a hearing of the House Agriculture Finance and Policy Committee last month.
“This legislation will help farmers diversify their crop rotations and cover crops, which will keep our soil protected in the winter,” Peterson said. “These practices create ecosystem services that promote habitat for wildlife and improve our water quality, while retaining nutrients, moisture and organic matter in our soil.”
Farmer John Snyder discussed healthy soil practices and passing his farm on to the next generation. | Land Stewardship Project
The bill easily moved out of the committee with an 11-1 bipartisan vote on Feb. 17. Though he supported the bill and said its intentions were commendable, Rep. Paul Anderson (R) said he believes individual farmers will move forward on their own without new policies or incentives.
“Your goals are laudable,” Anderson said. “But a lot of these things farmers are already doing. Establishing cover crops in this part of the country [northern Minnesota] can be quite challenging.”
More Republican opposition surfaced nine days later when the House Judiciary Finance and Civil Law Committee re-referred the bill to the agriculture committee on a 9-4 vote.
Rep. Peggy Scott (R) voiced the budget-conscious Republican consensus in not recommending the Lippert bill.
“I’ll be encouraging my members to vote no on this bill today,” she said during the hearing. “Farmers are already doing this sort of thing through precision agriculture.”
First-term Rep. Brian Pfarr (R), a community bank president, agreed.
“I’ve got a lot of farmers already doing this on their own,” Pfarr said, adding he doesn’t like government telling farmers what to do. Lippert reminded legislators that the program is voluntary, can save farmers production costs and has a limited price tag.
The bill seeks $2.75 million for each of the first two years, and it caps payments to individual farmers at $17,500 over the five-year trial period. The program would be administered by the Minnesota Board of Water and Soil Resources and the state’s soil and water conservation districts.
Rep. Brian Johnson (R) was more direct in his opposition, citing an unlikely scenario in Minnesota: “I don’t think those goals are sustainable unless we get rid of corn and beans.”
Lippert believes the bill has a solid chance of making it through the DFL-controlled Minnesota House with his party’s 70-64 edge over Republicans.
“We need solutions that increase our resilience in the face of our climate challenges,” Lippert said. “We also need solutions that can help us find the difference we can make in this shared struggle. I hear farmers talking with one another about the contribution they can make. It gives me hope.”
The same can’t be said in the Minnesota Senate, where Republicans hold a 36-31 edge, including two former DFLers now listed as independents and caucusing with the GOP. Lippert’s companion bill, carried by Sen. Kent Eken (DFL), remains stalled in the Senate Agriculture Rural Development Finance and Policy Committee. And with the week of March 8 the midpoint of the 2021 Minnesota legislative session, the clock is ticking.
Water Storage Bill Brings Farmers, Environmentalists Together
Water storage bills sponsored by a diverse set of organizations, including SF 81 and HF 518, appear to have more bipartisan support. And they have farm groups, wildlife conservationists and environmentalists working together.
Scott Sparlin is no farmer. But the veteran New Ulm, Minnesota, organizer understands the complex ties between agricultural forces and the environment.
For 33 years, Sparlin has been a vocal activist on issues regarding the Minnesota River and has seen water quality issues mount. But he also appreciates the economic significance and clout of rural Minnesota’s farming community, often cited as a culprit because of phosphorus and nitrogen runoff in the state’s waterways.
Tying those two critical state issues together brought Sparlin to the state Capitol in St. Paul three times this legislative session to testify for SF 81, which is designed to slow water flow through the Minnesota River Basin by encouraging partnerships with landowners along the 335-mile stretch of waterway.
“Over and over, from every part of the basin we heard water storage has to be addressed if we are going to be serious about protecting our infrastructure and improving our surface water,” Sparlin said during his testimony Feb. 22. “The good news is it can be achieved without adversely affecting agri-business or community development.”
Sparlin’s grasp of the sensitive ties between Minnesota River water quality issues and farming practices seems to be paying benefits. But it’s been a slow process for Sparlin, who has served three years as facilitator and coordinator of a loosely organized group, the Minnesota River Congress, which held 25 basin-wide meetings to gather input on such a bill.
“Diverse water storage practices, such as replacing historically drained lakes and wetlands and increasing soil health, will all help to achieve this goal,” Sparlin says. “The climatic trend and future prediction of increased rainfalls in short periods of time will only exacerbate the issue.”
The Minnesota River Basin consists of 13 watersheds and encompasses nearly 15,000 square miles, roughly 11 million acres, impacting 37 of the state’s 87 counties. Agricultural activities account for more than 92% of land use in the basin, according to the Minnesota River Basin Data Center.
The program advocates using cover crops to better hold water. DFL Gov. Tim Walz’s 2022-23 budget request calls for $1.5 million each year to implement such a water quality and storage program. Funding would be dedicated to the water and soil resources board and soil and water conservation districts.
Agriculture accounts for about 25% of Minnesota’s greenhouse emissions, according to the state Pollution Control Agency (PCA), which says 25 acres of cover crops remove as much atmospheric carbon as taking one car off the road.
After a January PCA report card gave the state’s agricultural sector a D+ grade in addressing current climate challenges, former state Sen. Ellen Anderson, now program director at the Minnesota Center for Environmental Advocacy, penned a blistering guest commentary in the Minneapolis Star Tribune.
In it, Anderson wrote: “Minnesota’s agricultural sector is a big contributor to greenhouse gas pollution, nearly on par with transportation and electricity. It is also the sector most at risk from the impacts of climate change, and an industry that could make progress quickly.”
A new report released by North Carolina Department of Commerce maps out how the state can tap into its offshore wind potential to become a manufacturing and workforce hub for development in the Southeast.
Authored by industry consultants BVG Associates, the report predicts that the U.S. will see 41 GW of OSW — with a $100 billion supply chain — by 2035, and that North Carolina’s strong manufacturing sector with its 470,000 workers could supply major components and materials to fuel that market growth. The state already has one of the largest manufacturing sectors on the East Coast, with $91 billion in real value added to the state’s GDP in 2019, representing 17.2%, according to the report.
Globally, the OSW market has grown on average 24% each year since 2013. “The larger this market becomes, the more the supply chain will be established on the East Coast,” the report says.
The report highlights a building momentum to “accelerate the offshore wind opportunity by driving North Carolina’s offshore wind targets and new wind farm developments to match the significant electricity consumption of the Southeast and Mid-Atlantic states [and] maximize economic, decarbonization and environmental benefit.”
Agreements with neighboring states could be leveraged to create a regional supply chain network, the report says, to promote the Southeast as a hub for OSW developers and suppliers. The groundwork for such multistate initiatives was laid in October 2020, when the governors of North Carolina, Maryland and Virginia signed a memorandum of understanding committing each state to develop at least 6.8 GW of OSW capacity. The MOU encourages the three states to align their individual regulatory requirements to support more production and optimize regional assets and resources.
“Offshore wind development, combined with our strong solar capacity, will bring more high paying, clean energy jobs to North Carolina while we continue to ramp up our fight against climate change,” Gov. Roy Cooper said in a statement about the MOU. “This bipartisan agreement with neighboring states allows us to leverage our combined economic power and ideas to achieve cost-effective success.”
North Carolina’s other climate policies also encourage growth in OSW, according to the BVG report. The state’s Clean Energy Plan aims to reduce greenhouse gas emissions in the state’s electric power sector 70% below 2005 levels by 2030 and reach net zero by 2050.
As the largest utility in the state, Duke Energy could be key to boosting OSW generation, the report said. Duke has pledged to reach net-zero emissions by 2050, but it currently has no OSW projects in development. The utility’s Integrated Resource Plan, submitted in September 2020, lays out six pathways to achieving that goal, although it is not clear that all pathways would succeed. Two of the pathways rely on significant offshore wind development, with no new natural gas generation.
The IRP is currently under review and is scheduled for a hearing with the North Carolina Utilities Commission on March 16. Duke participated in a commission technical conference focused on integrated resource planning on Tuesday, during which it made no mention of planning for future OSW development and downplayed the near-term need for energy storage and distributed energy resources.
The only OSW project moving forward in the state is Kitty Hawk Offshore, owned by Avangrid Renewables. Construction of the first phase could start in 2024 and will have the capacity to generate approximately 800 MW of electricity. The full project will have a generation capacity of 2,500 MW, or enough to power 700,000 homes. Over the next decade, it is projected to create almost $2 billion in total economic impact for Virginia and North Carolina, according to an economic impact report.
Solar energy industry advocates in Minnesota expect a slowdown in development under the Community Solar Gardens (CSG) program this year following state regulators’ approval of Xcel Energy’s proposed 4% reduction in the value of solar (VOS) rate (13-867).
The VOS rate — which sets compensation levels for CSG projects in Xcel’s territory — has been reduced in three of the last four years and now stands at 13% below 2017 levels.
Similar in concept to an urban farming co-op, CSGs were created for customers who want to use solar energy but can’t add rooftop panels. Customers who purchase shares of a participating solar site receive bill credits in return. Half of all U.S. households do not have access to rooftop solar resources, the Yale School of the Environment reported in 2019.
The state passed legislation in 2013 requiring the Department of Commerce to establish a methodology to compensate customers who provide distributed solar PV generation “for the value to the utility, its customers and society.”
The VOS methodology, which could be adopted by utilities as an alternative to net metering, has been used since 2017 to set rates for the CSG program in Xcel’s territory. It includes several categories of avoided costs, including fuel, plant operations and maintenance, generation capacity, transmission and distribution capacity, and environmental damages.
The program’s capacity has expanded to 784 MWac as of January 2021, including 435 applications submitted in 2020, about half of which are likely to be completed based on historical attrition rates. But David Shaffer, executive director of the Minnesota Solar Energy Industries Association, predicted only 150 MW in new capacity will be added during 2021 following the Public Utilities Commission’s VOS reduction, approved Jan. 28. The commission’s order was published March 9.
The VOS rate reduction doesn’t affect projects already developed or in production, but it does affect future development, said Timothy DenHerder-Thomas, general manager of Cooperative Energy Futures (CEF), one of the 115 solar site operators represented by MnSEIA.
Cooperative Energy Futures, which has completed at least eight community solar projects in Minnesota, says it does not plan any new projects in 2021 because of the reduced rate for solar bill credits. | Cooperative Energy Futures
He said the group is still completing projects begun in 2020: “That’s our major focus now.” Absent other economic changes, he said his co-op will probably not develop projects in 2021 under the value of solar rate approved by the commission.
“We’ve put a pause on new development” in 2021, he said.
Both Shaffer and DenHerder-Thomas said new CSG development has dropped in every year the VOS rate was decreased.
The commission’s order supported the Department of Commerce’s conclusion that “although certain aspects of the methodology leave some room for discretion, Xcel’s calculation is consistent with the approved methodology.”
“The VOS isn’t perfect, but it has been successful,” said Commissioner Matthew Schuerger at PUC’s Jan. 28 meeting. “It’s not intended to be perfect. It’s a balancing exercise. It’s balancing accuracy and simplicity and transparency. It’s a triangulation that’s really hard to do.”
The levelized rate was set at 12.75 cents/kWh for 2017, then reduced in 2018 to 12.02 cents and to 11.09 cents in 2019. The only increase came in 2020, when it was boosted to 11.52 cents. The levelized rate for 2021 is 11.04 cents/kWh, a 0.48-cent (4%) cut. (The levelized value is adjusted for inflation over the projected 25-year life of the solar project.)
Three-year Average
Industry groups and other stakeholders raised several issues in the docket, including Xcel’s decision to calculate solar production on an unweighted three-year average of 2017-2019.
MnSEIA and CEF said it was improper to use an unweighted average because 2017 data was based on only 27 MW of solar, while 2019 was based on 495 MW.
Cooperative Energy Futures’ 199-kW community solar array on the roof of Pax Christi Church in Eden Prairie, Minn., came online in July 2019. | Cooperative Energy Futures
DenHerder-Thomas said Xcel used only selected data from simulations and from only one CSG site, the Minneapolis-St. Paul Airport, in developing the proposed 2021 rate.
Xcel responded that its use of unweighted data over the three years smoothed out the impact of weather, resulting in a more reliable predictor of solar production for 2021. It also contended the methodology does not allow weighting as proposed by MnSEIA. The utility also rejected Cooperative Energy Futures’ suggestion to use multipliers to fill gaps in hourly metered data for systems of certain types, saying it would be inconsistent with the methodology and past commission orders.
There also was criticism of Xcel’s use of New York Mercantile Exchange natural gas futures for determining avoided fuel costs. Critics said NYMEX futures weren’t the best way forecast natural gas prices over the 25-year life of a project because of its volatility and short-term emphasis.
Natural gas prices bottomed out during the beginning of the pandemic, Shaffer said, and that was the price Xcel chose to use in the calculations. MnSEIA offered suggestions to represent the price more accurately during 2020, but they were ignored, he said.
The PUC said it was “not persuaded that the balance between precision, transparency and accessibility has shifted enough to compel a different approach to calculating avoided fuel cost at this time.”
Several parties also challenged the assumption that solar PV displaces only natural gas, contending coal is more often the marginal fuel displaced. The VOS methodology notes that changing to include displacement of coal might reduce avoided fuel costs while increasing avoided environmental costs.
“The comments challenging Xcel’s solar-weighted heat rate, avoided fuel cost and marginal-fuel assumption do not demonstrate that Xcel failed to apply the approved methodology; rather, they ask the commission to modify these components of the methodology, or to endorse one permissible option over another, equally permissible option chosen by Xcel,” the PUC said. “Because Xcel appropriately applied these components of the methodology, the commission will not reject Xcel’s proposed 2021 value-of-solar rate on these grounds.”
Delayed Interconnections
The PUC also heard calls to penalize Xcel for allegedly delaying interconnection of projects under the CSG program.
MnSEIA said Xcel’s failure to reduce interconnection delays harmed hundreds of customers and job creation in the sector. The association said it lost customers, had to idle workers and overpaid Xcel for interconnection studies because of the delays.
Xcel responded that the interconnection issue is not germane to the 2021 VOS determination. Xcel denied allegations that the company has a financial incentive in delaying customers from entering the CSG program, saying all program expenses are directly passed through to customers through fuel cost adjustments. It countered that MnSEIA’s motive in raising the issue was to delay approval of the 2021 VOS, keeping the higher 2020 rate in place.
The PUC also voted to order Xcel to provide a report evaluating the effectiveness of the residential adder — a bonus bill credit to residential subscribers to stimulate residential customer participation in the program — by March 26, when the adder is set to expire. Comments from MnSEIA, CEF and US Solar all supported extending the adder of 1.5 cents/kWh.
Cooperative Energy Futures’ 664-kW community solar array on the roof of the Public Works building in Edina, Minn., went online in November 2018. | Cooperative Energy Futures
The five-member commission unanimously directed Xcel and the Department of Commerce to discuss a new “profile-based” approach to determining the proxy fleet shape used for the 2022 VOS.
This profile would include larger solar operations in addition to CSGs and would utilize “as-built” information on all installations.
The fleet shape impacts values for effective load carrying capacity, peak load reduction, loss savings and solar-weighted heat rate. The solar-weighted heat rate attempts to capture the emissions of fossil fuel resources displaced by new solar.
The PUC ordered Xcel to propose changes for its 2022 value of solar by July 1.
California regulators and lawmakers are trying to avoid a repeat of last year’s unprecedented use of public safety power shutoffs (PSPS) to prevent utility equipment from igniting wildfires — and the anger it provoked among ratepayers.
The California Public Utilities Commission and the state Assembly’s Utilities and Energy Committee each held hearings last week to determine what can be done in the coming months to limit PSPS use by the state’s three large investor-owned utilities.
Assemblymember Chris Holden chaired a March 3 hearing on PSPS. | California State Assembly
PSPS were used 30 times between 2013 and 2019, and 33 times last year alone, energy committee Chair Chris Holden said. “What happened?” Holden asked at the hearing, which was held at the state capitol in Sacramento.
“It’s safe to say that we’re all frustrated by the use of public safety power shutoffs by our state’s electric utilities,” he said. With climate change and aging infrastructure, “we do understand the need to use this tool, but it absolutely must be used as a last resort — judiciously, during extreme weather events, when there is no other way to ensure that utility equipment will not come into contact with vegetation and start a fire.”
Southern California Edison and, to a lesser extent, Pacific Gas and Electric bore the brunt of criticism at the hearings, while San Diego Gas & Electric received relatively little blowback.
SCE Responds
PG&E appeared to have made progress in limiting PSPS events in 2020 and communicating with its customers, Holden said. SCE, however, doubled its PSPS events from 2019 and had “repeated failures to follow protocols at the expense of customers and public safety,” he said.
“They repeatedly assured the CPUC president that, ‘We are going to [change]. We plan to. We want to,’” Holden said. “But in the moment, they did not. This raises the question of whether the [CPUC and other] agencies have sufficient enforcement tools.”
State authorities need tools “that can be used in real-time if a utility is calling events unnecessarily or failing to follow proper notification protocols for customers, public safety partners and other state agencies,” he said.
In late January, the CPUC held a hearing to examine what it called SCE’s mishandling of PSPS events. It demanded the utility produce a corrective action plan with specific goals and timelines for improvement. (See CPUC Slams SCE Over Power Shutoffs.)
On March 1, SCE presented its plan to the CPUC in a follow-up workshop.
Erik Takayesu, the SCE vice president who oversees PSPS readiness, noted that 2020 was a record year for wildfires in California with more than 4 million acres burned and an unusually long fire season in Southern California. Many of SCE’s PSPS events occurred later in the year, he said.
“Two-thirds of our deactivations occurred from November through the end of the year … [with] particular hardships experienced by customers over the holiday season,” Takayesu said.
SCE turned off power on Thanksgiving Day and Christmas Eve, sending out late or confusing notices of the PSPS events and angering residents.
“I and the members of our team have heard the concerns and frustrations of our customers and communities who have been affected by PSPS events,” Takayesu said.
The utility made significant progress in 2020 but needs to do more, he said.
“Our main emphasis in 2020 was focused on the distribution system, creating segmentation plans for every one of our 11,600 circuits in our high fire risk areas,” Takayesu said.
The utility removed 25,000 customers from the scope of PSPS events last year, but 230,000 customers were subjected to repeat de-energizations, another cause of customer frustration.
“We now need to further direct our efforts to focus on the most frequently impacted circuits,” Takayesu said.
Phil Herrington, Southern California Edison senior vice president of transmission and distribution, responded to criticism of the utility. | California State Assembly
SCE intends to turn its attention this year to circuits that have experienced four or more de-energizations since 2019. Continued grid hardening will reduce the frequency of PSPS and improve reliability across the utility’s grid, he said.
As of Feb. 19, SCE had identified 72 circuits for potential expedited upgrades such as covered conductor. It intends to complete the work by Oct. 1, when Southern California’s peak fire season typically starts, the utility told the CPUC.
In Thursday’s legislative hearing, Phil Herrington, SCE senior vice president for transmission and distribution, said that “despite the challenges posed by COVID-19, we met or exceeded nearly all the goals in our 2020 wildfire mitigation plan.”
That included installing more than 960 circuit miles of insulated wire, over 6,000 fire-resistant bolts and nearly 600 weather stations, Herrington said. SCE also removed more than 12,000 hazard trees that could have fallen into power lines.
Enhanced Oversight of SCE
Such assurances did not mollify some officials at the hearings.
CPUC President Marybel Batjer presided over the SCE workshop and testified before lawmakers last week.
The commission, she said, has been trying to get the state’s investor-owned utilities to improve their PSPS execution and limit use of the practice since October 2019, when PG&E blacked out 2.4 million residents over large swaths of the state, generating public backlash. (See California Officials Hammer PG&E over Power Shutoffs.)
CPUC President Marybel Batjer and Executive Director Rachel Peterson discussed PSPS performance by the state’s investor-owned utilities. | California State Assembly
Batjer agreed with Holden that in 2020, “for PG&E, we appear to see improvements … on a few fronts [including] overall reduction in scope and scale [of PSPS events] compared to 2019.” The state’s largest utility has improved its planning for community resource centers to serve residents during blackouts and has improved its PSPS event forecasting as well, she said.
The utility still needs to work on sharing information with local agencies and tribal governments, and it needs to expand its battery-backup program to help medically vulnerable customers during PSPS events, she added. (See PG&E Working to Improve Safety Blackouts.)
“Its notification protocols [for customers] also require improvements,” she said.
SDG&E also needs to improve communication with local authorities and beef up its battery backup program for medical baseline customers, Batjer said.
SCE has been more problematic. The state’s second largest utility “has required special attention and has been the subject of two public meetings at the commission” this year, Batjer said.
“There are many areas where I believe Edison did not measure up to the standards … its customers deserve,” she added.
The utility initiated 16 PSPS events between May and December last year, most of which were in November and December, including the two major holidays, Batjer noted.
“Among the various problems we observed were issues with the level of transparency around Edison’s PSPS decision-making process, inadequate notification to impacted customers, poor coordination and communication with state and local governments, shortcomings in identifying and notifying medical baseline and functional needs customers and efficient PSPS post-event reporting to the commission,” she said.
“In addition, we continue to have serious concerns with the pace at which Edison has been deploying backup power to help vulnerable customers cope with PSPS events.”
One of SCE’s major shortcomings was its under- or over-notification of customers potentially affected by PSPS, Batjer said.
“Only 20% of the customers it gave advanced notice to this past fire season were affected by a PSPS event,” she said. “While it is desirable to have as few customers de-energized as possible, there is something wrong with this planning approach if you’re consistently putting large numbers of customers on notice and then nothing happens.”
There were also too many instances in which customers were not notified before losing power, including on Thanksgiving, she said.
“Forecasting and communications must improve,” Batjer said of SCE.
The CPUC had to enhance its oversight of PG&E’s PSPS practices going into the 2020 fire season, she noted. “We’re doing this now with Edison … to ensure they live up to their commitments under their corrective action plan.”
Upcoming Actions
The CPUC is planning to host a public workshop later this month to hear from utilities and impacted communities on lessons learned from 2020 PSPS.
“These lessons will inform another round of updating of our PSPS guidelines, which we commenced on Feb. 19,” Batjer said. “We will continue to hold public meetings as we enter the critical months of the wildfire season to assess the utilities preparedness. If required, we will utilize our expansive enforcement authority over the utilities to deliver the type of behavior customers deserve and expect from providers of an essential service.”
The results of an investigation into IOU power shutoffs, initiated in 2019, will be released soon, she said.
PSPS may continue for years as utilities upgrade their systems, but the goal is to stop needing it, Batjer said.
“I want to reiterate the CPUC’s commitment to driving the utilities towards zero need,” she said. “The use of PSPS and the loss of power causes major disruptions to households, businesses, medical facilities, communication carriers and other critical infrastructure. It strains state and local emergency and public safety personnel.
“The public deserves better, and we are working to ensure they are better served by the utilities,” she said.
Former ERCOT CEO Bob Kahn has rejoined the Texas grid operator’s Board of Directors as it begins to reconstitute itself after a wave of resignations following the massive February power outage.
Kahn, currently the Texas Municipal Power Agency’s general manager, was elected Friday by the municipal segment members as their representative on the board. He served as ERCOT’s CEO from 2007 to 2009 and previously served on the board from 2002 to 2006.
Bob Kahn | ERCOT
Kahn replaces Austin Energy General Manager Jackie Sargent, who resigned after testifying before the Texas Legislature on Feb. 26. He told the Austin American-Statesman he plans to ask questions about the February power outage that cost ERCOT half its generating capacity and led to widespread blackouts.
Also last week, the independent retail electric provider segment elected Demand Control 2’s Shannon McClendon as its representative. She replaces Just Energy’s Vanessa Anesetti-Parra, who was among the out-of-state board members that resigned Feb. 23. (See ERCOT Chair, 4 Directors to Resign.)
The additions bring the board’s membership up to 10 directors. The five unaffiliated seats and the cooperative segment’s representative remain open. Directors representing industry segments serve one-year terms and are unpaid.
Kahn joined TMPA in 2012. The public power organization ran the coal-fired Gibbons Creek Generating Station for the member cities of Bryan, Denton, Garland and Greenville. The plant hasn’t run since 2018 and was sold in February to Gibbons Creek Environmental Redevelopment Group, which will take three years to demolish it and complete environmental remediation.
Prior to being named ERCOT’s CEO, Kahn spent 10 years at Austin Energy as general counsel and then deputy general manager. He also served in the Texas Public Utility Commission general counsel’s office and represented public power in the state’s deregulation legislation.
The U.S. Bureau of Ocean Energy Management (BOEM) on Monday concluded its environmental review of the Vineyard Wind I project off the coast of Massachusetts.
“More than three years of federal review and public comment is nearing its conclusion, and 2021 is poised to be a momentous year for our project and the broader offshore wind industry,” Vineyard Wind CEO Lars Pedersen said in a statement.
BOEM said it is working to issue a record of decision whether to approve or disapprove the proposed project, or approve it with modifications. The U.S. Army Corp of Engineers and the National Marine Fisheries service will sign the record of decision for their respective authorization decisions.
“We look forward to reaching the final step in the federal permitting process and being able to launch an industry that has such tremendous potential for economic development in communities up and down the Eastern seaboard,” Pedersen said.
The final environmental impact statement (EIS) signals the direction BOEM is leaning toward in its decision. BOEM could approve Vineyard Wind’s construction and operations plan with specific changes, including capping the number of turbines built for the project at 84. Depending on the final turbine capacity used, the project could have as few as 57 turbines.
In addition, BOEM could prohibit wind turbine installations in six locations in the northernmost portion of the project lease area. BOEM may also require the turbines be installed in a north-south and east-west orientation with a minimum distance of one nautical mile between them.
Project officials estimate Vineyard Wind will reduce electricity rates by $1.4 billion over the first 20 years of operation and reduce carbon dioxide emissions by 1.68 tons annually, the equivalent of taking 325,000 cars off the road each year. The project is estimated to create 3,600 jobs in Massachusetts and spur over $200 million in economic activity, according to the Business Network for Offshore Wind (BNOW).
“This is the day the U.S. offshore wind industry has been anxiously awaiting for years,” BNOW CEO Liz Burdock said in a statement. “[This] announcement provides the regulatory greenlight the industry needs to attract investments and move projects forward.”
Vineyard Wind, a joint venture between Avangrid and Copenhagen Infrastructure Partners, said it expects to begin delivering energy from the project to Massachusetts in 2023.
Impact on Fish Habitat
Fisheries along the New England coast have opposed the Vineyard Wind project and advocated for changes to mitigate the impacts of the turbines and offshore cables on scallop spawning grounds and fishing gear.
The final EIS said that “most potential unavoidable adverse impacts associated with the [project as proposed], such as disturbance of habitat or incremental disruption of typical daily activities, would occur during the construction phase or would be temporary.”
However, the project “could include effects on habitat or individual members of protected species, as well as potential loss of use of commercial fishing areas.”
Vineyard Wind agreed to provide fisheries mitigations for Rhode Island “after multiple discussions and negotiations,” according to the review, including a $4.2 million fund for direct compensation to Rhode Island fishermen for loss of equipment or claims of direct impact.
The project will also provide Rhode Island with $12.5 million to establish a Rhode Island Fisheries Future Viability Trust and work with the Massachusetts Executive Office of Energy and Environmental Affairs to establish a Compensatory Mitigation Fund for $19.2 million and a Fisheries Innovation Fund for $1.75 million.
