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December 17, 2024

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Podesta: Economics of Clean Energy ‘Have Simply Taken Over’

WASHINGTON, D.C. — David Crane opened the Department of Energy’s Deploy 2024 conference with the facts and figures of the money he and other DOE officials have helped to distribute from the Infrastructure Investment and Jobs Act and the Inflation Reduction Act over the past three years.

“We’ve committed over $95 billion in grants and loans, and with more [going out] each day,” Crane, DOE’s under secretary for infrastructure, told an audience of more than 1,800 at the Walter E. Washington Convention Center. “So, within the next few days and weeks, it will be over $100 billion and moving northwards.”

That money has gone to about 1,900 grant selectees and another 4,500 recipients of formula grants, Crane said. “And all that is tied with over $100 billion — well over $100 billion — committed from the private sector.”

Those public and private dollars have created irreversible momentum the U.S. clean energy transition, said White House Senior Advisor John Podesta, who closed the conference’s opening plenary with a call to action for the private sector facing the uncertainties of the incoming Trump administration.

Donald Trump and congressional Republicans have declared their intention to roll back the IRA and other clean energy initiatives. Chris Wright, a fracking CEO and Trump’s nominee for secretary of energy, is an unabashed advocate of fossil fuels.

But, Podesta countered, “the economics of the clean energy transition have simply taken over. New power generation is going to be clean. The desire to build our next generation nuclear is still there. The [data center] hyperscalers are still committed to powering the future with clean energy. The auto companies are still investing in electrification and hybridization.

“All those trends are not going to be reversed,” he said. “Are we facing some new headwinds? Absolutely. But will we revert back to the energy system of the 1950s? No way.”

Echoing Podesta, the buzz at the conference was upbeat. Crane noted that many of DOE’s funding opportunities have continued to draw more applicants than could be funded. The Grid Resilience and Innovation Partnerships Program was eight times oversubscribed, he said.

Crane also pitched to investors at the event that DOE-funded projects are well-vetted and derisked.

energy

David Crane, DOE under secretary for infrastructure | © RTO Insider LLC

“One of the most important things … the Department of Energy has done for the private sector is that we put immense effort into picking the best of the best in terms of projects,” he said. “Of course, any [investor] here is going to do their own due diligence, but I think it’s fair to say that if the Department of Energy has … provided a grant to a company, if we’ve provided a loan to a company, they’ve been subject to extensive due diligence, and we believe the technology that we’re financing can scale and the projects can be commercially viable.

“Treat us as like a Good Housekeeping seal of approval,” he said.

Podesta also argued that U.S. innovation in clean energy will continue to be critical to ensure the nation can compete in global markets.

“The prices of clean technologies will keep dropping, and the need to compete with the rest of the world, as they move full steam ahead on clean energy, is going to only increase and increase and increase,” he said. “Now it’s up to you, America’s clean energy entrepreneurs and clean energy companies, to lead that transition.

“We need you to keep innovating, showing the world that America leads with big ideas.” Podesta said. “We’re counting on you to carry this work forward, for the sake of your businesses, for the sake of the communities you’ve invested in, for the sake of the American people, of our economy, our security, our young people and our planet.

“Thank you for what you’re doing. Just keep doing it. Do it faster. Do more of it, and we’ll all be better off.”

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New Jersey Plans for 2025 Community Solar Solicitation

New Jersey has launched a stakeholder input campaign for its community solar program as the state prepares to solicit interest for 250 MW of capacity in 2025 after two nearly fully subscribed allocations in the program’s first 12 months. 

The New Jersey Board of Public Utility (BPU) allocated 225 MW in the fully subscribed first allocation, which the agency launched in November 2023, and an additional 275 MW of capacity in the second allocation, which was launched in May 2024, agency officials said at a Dec. 3 public hearing. The BPU said it allocated all but 4.8 MW of the available capacity in the second solicitation. 

The BPU said it will collect written stakeholder comments until Dec. 16 and review whether the program needs to be adjusted before the opening of a new solicitation in coming months. 

Most of the dozen or so speakers at the hearing, many from the solar development community, commended the progress of the program, which is a key element in the state’s goal to reach 12.2 GW of solar energy by 2030 and 32 GW by 2050. 

Yet the most salient comments focused on the future, and how the state responds to the incoming Trump administration. The president-elect has expressed opposition to renewable energy and the subsidies for solar and other sectors in the Inflation Reduction Act. 

Lyle Rawlings, president of Mid-Atlantic Solar Energy Industries Association (MSEIA) and a solar developer, asked how the BPU would “account for potential changes” in the Investment Tax Credit, which at present can cover 30% of a solar project cost. 

Industry analysts have expressed fears that the new administration will seek to shrink or delete the ITC, citing the more than 50 votes taken by Republicans in the House of Representatives in the past to repeal parts of the IRA. (See Chesapeake Solar Industry Prepares for Trump 2.0 ‘Solarcoaster’.) Trump also has said he expects to implement a wide-ranging tariff program, including a 10% tariff on China, the source of much solar equipment. 

“The tariffs and changes to the ITC could be making things much more expensive for community solar,” Rawlings said. “And if this application window incorporates a new incentive rate that does not take that into account, then a whole year-plus of development is going to be severely handicapped by that.” 

Uncharted Territory

Fred DeSanti, executive director of the New Jersey Solar Energy Coalition, urged the BPU to prepare for sector changes. “We’re in kind of uncharted territory with federal policy,” he said. “The need to remain flexible during this period, I think, is very important because we don’t know what’s coming.” 

Sawyer Morgan, a research scientist at the BPU’s Division of Clean Energy, said the BPU is not aware of any changes in the ITC and would appreciate input from the solar sector on how to address the issue. 

“At this point, we can’t account for what we do not know,” he said. “In the event that there are changes to the ITC, I would anticipate that the board would take these into account in any future evaluations. We would certainly consider any incentives to be responsive to changes in the general marketplace, and would take that into account for future registrations.” 

In response to another question about a cut in the ITC, Sawyer said “any future changes made to the ITC will be taken into account for incentives made available to future rounds of applications.” 

Pent-up Demand

Community solar projects target users who either cannot or do not want to have solar on their roofs but seek to support a clean energy initiative. To make the projects work, the developer must sign up subscribers, who commit to using the clean energy and in turn receive a credit on their utility bill, reducing the electricity cost by a set percentage. 

New Jersey had 4.98 GW of installed solar capacity in October, including 109 community solar installations that total 166,632 kW, or about 4% of the state’s installed capacity, according to BPU figures. The state has an additional 364 projects, or 522,291 kW of capacity, in the pipeline. 

The state enacted its first community solar pilot program in 2019 and its second in 2021. The first program, which attracted 252 applicants, approved 45 projects totaling 75 MW. The second pilot, which attracted 412 applications, awarded 105 projects totaling 165 MW.  

The BPU enacted a permanent program in August 2023, creating a program for community solar projects smaller than 5 MW developed on rooftops, carports, canopies over impervious surfaces, contaminated sites, landfills or bodies of water. Projects in the program are eligible for an incentive of $90/MWh (See NJ Opens Community Solar and Nuclear Support Programs.) 

Charles Coggeshall, mid-Atlantic regional director for the Coalition for Community Solar Access (CCSA), said the program is “doing well.” He attributed it in part to the “pent-up demand that was building up over several years as we were awaiting the final rules, and then ultimately, the program opening.” 

The fact that the first two solicitations under the permanent program were so well subscribed is “indicative of that pent-up demand and the kind of energy and interest by the market,” he said. 

“We believe that the pent-up demand, and sort of lowest-hanging fruit, has been kind of tapped in large part,” Coggeshall said, adding that he expects sites from now on to be “more challenging” and interconnection costs to rise as “the grid becomes kind of more constrained with regards to available places to interconnect.” 

The next few months, and “potential impacts on tax incentives and tariffs,” would indicate a preference for not rocking the boat by changing incentive levels, he said. 

Attracting Subscribers

Rawlings, of MSEIA, urged the BPU to do more to increase the percentage of low- to moderate-income (LMI) subscribers to community solar projects beyond the 51% requirement that is the current rule, and to have an “aspirational goal” of 100%. He said they could include in the ranking of applications to the program the percentage of LMI subscribers they expect to sign up and the discount the subscribers would receive. 

“We believe this will drive developers to find ways to serve more LMI customers,” he said. 

Other developers said the expected introduction in January of a consolidated billing system for new and existing projects will make it easier to attract subscribers. Since the program began, subscribers have received two bills: their regular bill plus a separate bill for their community solar subscription. (See Billing Key to NJ Community Solar Growth.) 

Supporters of a consolidated bill say it would be simpler for subscribers to understand, and its clarity would encourage potential subscribers to get involved. 

DeSanti called the introduction of consolidated billing “absolutely essential to making this program work well and to drive some cost out.” 

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Texas PUC’s Glotfelty to Resign from Commission

Jimmy Glotfelty said Dec. 4 he will resign from the Texas Public Utility Commission at year’s end, leaving the regulator two short of a full complement. 

In a letter to Gov. Greg Abbott, Glotfelty offered his resignation, effective Dec. 31, saying it has been “an honor and privilege to serve the people of Texas” as a commissioner. Also leaving at the same time will be Lori Cobos, who announced her resignation in November. (See Texas PUC’s Cobos to Leave Commission.) 

Asked to elaborate on his decision, Glotfelty told RTO Insider, “Just time to go build some infrastructure and nuclear plants in Texas. You cannot do that inside the government.” 

Glotfelty chaired Texas’ Advanced Nuclear Reactor Working Group, which wrapped up more than a year’s worth of work in November with a 78-page report meant to ensure Texas is “the energy capital of the world.” 

“We hope this is a springboard to greater, bigger, better things in the nuclear space in Texas, and this is just the beginning,” he said as he rolled out the report during the Texas Nuclear Summit. (See Texas Now Wants to be No. 1 in Nuclear Power.) 

In his letter, Glotfelty said he was “especially grateful” to lead the nuclear working group and implied that’s where his future will take him. 

“We now have a lot of work to do [to] implement its recommendations, and I remain committed to continuing the effort to support the leadership on this issue,” he wrote. 

Glotfelty told Abbott he was “proud of the work we have accomplished to address the challenges that face the Texas electric system.” He listed efforts to strengthen the ERCOT system after the disastrous 2021 winter storm, expanding the transmission system, developing an aggregated distributed energy resource pilot program, and improving the grid’s reliability.  

With the departures of Glotfelty and Cobos, the PUC will begin the new year with only three commissioners, two short of a full slate. 

Abbott appointed Glotfelty to the PUC in 2021. His term expired in September, but he has continued to serve at the governor’s pleasure.  

Glotfelty brought a long career in the energy industry to the PUC, including leadership roles with Calpine, ICF Consulting and Quanta Services. He was a founder and executive vice president at transmission developer Clean Line Energy and founded and led the U.S. Department of Energy’s Office of Electricity. Glotfelty served as policy adviser and legislative directors for several political figures, including DOE Secretary Spencer Abraham, Texas Gov. George W. Bush and U.S. Rep. Sam Johnson (R). 

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Industry Seeks Flexibility on New Supply Chain Reliability Standards

Electric industry participants asked FERC for flexibility in setting the new supply chain risk management (SCRM) standards the commission suggested in a notice of proposed rulemaking issued in September (RM24-4).  

Edison Electric Institute, Electric Power Supply Association and the National Rural Electric Cooperative Association filed joint comments Dec. 2 saying they support efforts to improve supply chain risk management practices but have qualms with FERC’s specific proposals. 

“As FERC states in this NOPR, while the global supply chain introduces risk to the security and reliability of the BPS by creating potential attack surfaces for threat actors to exploit, it also provides the opportunity for significant customer benefits such as low cost, product variety and rapid innovation,” the joint trade groups said. 

As the technology to operate the grid evolves, grid owners and operators will continue to be responsible for security, but that responsibility is shared by suppliers, vendors and manufacturers. Revisions to mandatory standards need to strike the proper balance between the responsibilities of industry and suppliers, the trade groups said. 

FERC’s proposed rule would require responsible entities to evaluate equipment and vendors to better identify supply chain risks, requiring NERC to establish a maximum time frame between when an entity performs its initial risk assessment during the procurement process and when it installs the equipment. Responsible entities would have to take steps to validate supplier claims around any risks. (See FERC Proposes Further Cybersecurity Measures.) 

The trade groups said they don’t support the commission’s recommendation that entities should reevaluate the risks of installing any piece of equipment that has sat in storage for a long time.  But they did agree with a proposal to perform periodic reassessments of vendors that consider the criticality of a service or product and changed circumstances, such as a merger or a security event associated with a supplier. 

Forcing such reassessments could prove difficult contractually with overseas suppliers, who might not be required to go through reviews, the groups said. 

While FERC stopped short of requiring responsible entities to guarantee the accuracy of information they get from vendors, the trade groups oppose overarching requirements for vendors to supply supporting evidence or independent certifications. 

“Mandatory Reliability Standards should use a risk-based approach that allows entities to determine when and what validation is required for vendor-provided supply chain risk management information based on entity-defined criteria,” the groups wrote. “This approach allows entities to focus on products and services that represent the greatest risk to reliability while minimizing the increased workload associated with validating vendor responses.” 

The trade associations asked FERC to support a risk-based approach to developing future supply chain standards, which, given the growing number of suppliers, will require scalable mechanisms to identify and address risks. 

‘Continuous Monitoring’

Amazon Web Services (AWS) also weighed in on the NOPR, urging FERC to use a risk-based approach on any requirement to restudy equipment in storage before it gets installed. AWS advised against a blanket requirement for reassessment, saying it should only be triggered by events such as a change in supplier ownership, geopolitical events or new security exploits. 

Rigid time frames could lead industry participants to miss important risks that arise right after a reassessment, while adding costs with no major benefits, AWS said. 

“Continuous monitoring of assets in production is a more effective approach to supply chain risk management by increasing visibility into potential risks and the ability to respond to emerging risks,” AWS said. “NERC should credit programs that include continuous monitoring to complement periodic full reassessments.” 

AWS urged FERC to accept the use of third-party certifications and technology solutions to help responsible entities stay on top of supply chain risk management. 

“Use of third-party certifications should be explicitly supported as a valuable aspect of risk assessment because such use leverages high-quality risk analyses and security practice verification provided by disinterested third parties,” the company added. 

‘Aggressive Approach’

The ISO/RTO Council said it supports robust supply chain risk management practices and argued that any directives to NERC should recognize that responsible entities are best suited to determine how and when to evaluate risks. 

“Neither NERC nor a NERC standards drafting team will fully understand or appreciate each individual responsible entity’s unique supply chain risks,” the IRC said. “Although NERC can develop a requirement that responsible entities identify risks and specify the timing requirements for equipment and vendor evaluations, each individual responsible entity is in a better position to understand the risks related to its unique supply chain.” 

IRC also urged FERC to tread lightly on requiring confirmation of vendor’s claims about supply chain risks because that is difficult and potentially cost-prohibitive. Any rules should give responsible entities flexibility to pick a validation process — such as a direct or third-party audit, it said. 

“This flexibility will assist compliance in the short-term,” IRC said. “Any commission directive to NERC should also encourage and drive further consideration of a longer-term evolution that would take validation responsibilities off of each responsible entity and allow for the development of third-party verification and other means to more efficiently undertake this important validation task.” 

While many in the industry argued for flexibility, the Secure the Grid Coalition, which calls itself “an ad hoc group of policy, energy and national security experts,” argued the NOPR is a small step and said FERC should do more to secure the industry’s supply chain risk management (SCRM). 

“The continued reliance on generic improvements to SCRM standards without targeted action against known risks from Chinese-manufactured transformers and other critical grid equipment leave significant vulnerabilities unaddressed,” the conservative group told FERC. “To ensure the reliability and safety of the U.S. electric grid, FERC must take a more comprehensive and aggressive approach.” 

Utilities should be incentivized to buy American products, something FERC can encourage with an aggressive messaging campaign that it is no longer satisfied with the “status quo of its entities purchasing vital assets — particularly transformers and other critical grid equipment — from hostile nations,” the coalition said. 

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NY Contracts for $4.7B of Wind, Solar Projects

New York state has executed contracts for proposed onshore wind and solar projects totaling 2,341 MW of capacity at an expected cost of over $4.7 billion.

The New York State Energy Research and Development Authority (NYSERDA) reported the contracts Dec. 3, a little over a year after it launched the state’s 2023 Renewable Energy Standard solicitation.

The 23 contracts are intended to get New York closer to its decarbonization goals and are expected to generate about 5 million MWh of electricity per year. The nominal weighted average strike price of the projects over their lifetime is $94.73/MWh, which would average about 70 cents on the average customer’s monthly utility bill.

All the projects are in upstate New York, and all but one is far removed from the New York City area, where the need for clean energy is greatest. Thanks to upstate nuclear and hydropower generation, a high percentage of northern New York’s electricity already is emissions free. The densely populated downstate area still relies heavily on fossil-fired generation.

Eliminating transmission bottlenecks to move the clean power north to south is another priority for the state.

NYSERDA President Doreen Harris said in a news release: “Today we celebrate 23 more projects that will deliver clean, sustainable energy to our state’s electric grid. New York continues to provide a reliable market for renewable energy projects, and by facilitating responsible development of these projects, we are protecting our natural resources and creating healthier communities.”

The word “celebrate” is appropriate, given events of the past 13 months.

Developers holding New York Tier 1 renewable energy certificate (REC) contracts sought inflation adjustments after the contracts became financially untenable. The state rejected the request in October 2023, prompting a mass cancellation of contracts and evisceration of the state’s renewable energy portfolio.

The 2023 Tier 1 solicitation, launched Nov. 30, 2023, was one of the state’s efforts to recover.

Importantly, the 23 contracts awarded in this solicitation are going to later-stage projects, which should limit the delay and cancellation risks that face early-stage projects. NYSERDA said several of the contracted projects already have started construction, and all are expected to be operational by 2028.

This will help the state get closer to its statutory 2030 target of 70% renewables; earlier this year, officials acknowledged they are likely to miss that goal, perhaps by a wide margin.

The upfront investment to build these 23 projects, expected to surpass $4.7 billion, will be borne by the private sector. The REC money does not start flowing to the developers until the projects are fully permitted and fully operational.

The contracts announced Dec. 3 are for the following projects and developers:

    • Dog Corners, Cordelio Power, Cayuga County.
    • Scipio Solar, Cordelio Power, Cayuga County.
    • ELP Granby Solar II, VC Renewables, Oswego County.
    • Garnet Energy Center, NextEra Energy Resources, Cayuga County.
    • Trelina Solar Energy Center, NextEra Energy Resources, Seneca County.
    • Cider Solar Farm, Hecate Energy and Greenbacker Renewable Energy Co., Genesee County.
    • Highview Solar, Cordelio Power, Wyoming County.
    • Heritage Wind, Apex Clean Energy, Orleans County.
    • Excelsior Energy Center, NextEra Energy Resources, Genesee County.
    • Little Pond Solar, Greenbacker Renewable Energy Co., Orange County.
    • Tayandenega Solar, Greenbacker Renewable Energy Co., Montgomery County.
    • Rock District Solar, Greenbacker Renewable Energy Co., Schoharie County.
    • Grassy Knoll Solar, Cordelio Power, Herkimer County.
    • Flat Hill Solar, Cordelio Power, Herkimer County.
    • Watkins Road Solar, Cordelio Power, Herkimer County.
    • Hills Solar, Cordelio Power, Herkimer County.
    • Flat Stone Solar, Cordelio Power, Oneida County.
    • Brookside Solar, AES, Franklin County.
    • Baron Winds II, RWE, Steuben County.
    • Canisteo Wind Energy Center, Invenergy, Steuben County.
    • Valley Solar, Cordelio Power, Tioga County.
    • Alle-Catt Wind, Invenergy, Allegany and Cattaraugus counties, Wyoming County.
    • Bear Ridge Solar, Cypress Creek Renewables, Niagara County.
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SPP Stakeholders Endorse Need Dates for Delayed Transmission Projects

SPP stakeholders have endorsed a pair of winter-weather staging dates for transmission projects after two months of discussions and negotiations that delayed their approval by the Board of Directors. 

The Markets and Operations Policy Committee on Dec. 2 voted to endorse the need dates for a pair of projects from the 2024 Integrated Transmission Planning assessment, sending the issue onto the board and its Members Committee for final consideration during their Dec. 9 conference call. 

The board delayed a decision on the projects’ need dates — the earliest that staff identify that a project is needed — during its October meeting over a lack of consensus. (See SPP Board Approves $7.65B ITP, Delays Contentious Issue.) 

SPP staff met three times over eight days in November with the Transmission and Economic Studies working groups to iron out their differences over the staging issue. They held separate discussions on two winter storm-based models, reviewed staging data on the Year 2 Winter Storm Elliott model and agreed on an incremental staging concept to prevent Elliott-level load shed. 

Sunny Raheem, SPP’s director of system planning, said staff’s focus was ensuring stakeholders could review the two models and provide additional education on the staging approach used to determine the projects’ need dates and in-service dates. 

“There was a lot of involvement from the stakeholder groups and being able to make sure those meetings were progressing forward and accurately within the board’s direction,” he said. 

The discussions resulted in MOPC’s endorsement of a December 2028 date for the 345-kV Tobias-Elm Creek transmission line on the western side of SPP’s footprint, an 85-mile segment valued at $887.46 million. It cleared the two-thirds approval threshold with 71%. 

The TWG and ESWG recommended a 2028 need date for the 154-mile, $484.09 million 345-kV Buffalo Gap-Delaware project from Kansas into Southwest Missouri, but Evergy was able to amend the motion to move the need date to December 2025. MOPC eventually approved a motion that included the 2025 need date as resolving the remaining Elliott target area’s reliability needs, consistent with SPP staff’s incremental staging approach. It passed with 75% approval. 

The first project is expected to increase transfer capability from SPP North to SPP South and decrease the chances for load shed. The second brings a new extra-high-voltage source into Missouri to support system voltage and transfers from SPP. 

Evergy’s Mo Awad pressed for the earlier 2025 need date, saying a related 345-kV project with a 2025 need date would not resolve low-voltage issues experienced during Elliott. He said the 2025 date is consistent with staff’s “shorter lead time” approach referenced in an ITP staging process information paper. 

SPP defines projects needed within three years to be “short-term reliability projects.” SPP must explain the reliability issues and post them for a 30-day comment period before the board’s determination. Incumbent transmission owners hold the right of first refusal. 

Rebuild projects in a ROFR state and needed after three years are open to competitive bids under FERC Order 1000. 

“I don’t see any of these projects being in service before the winter of 2028. That’s just the reality of building big transmission projects,” Kansas Power Pool’s Larry Holloway said. “It appears to me that this is just an argument to avoid the competitive process.” 

Awad responded during an extended back-and-forth between the two with several examples of 345-kV projects that Evergy has been able to complete on time and on budget.  

“Those are concrete examples that we complete 345-kV projects by the in-service data as accepted by SPP on the [notification to construct],” Awad said. “I would offer that if those projects go competitive, they’re not going to expedite the projects. They’re going to slow them down. If they’re not competitive, they’re going to go to the [designated transmission owner], and they’re going to start engineering and right-of-way acquisition immediately. If those projects go to the competitive process … it will take a year at least to award the project to an individual. That’s a year that could be used for engineering and right-of-way acquisition.” 

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Power Market Costs Behind Rate Increases, PGE Says

Portland General Electric’s rate hikes largely stem from increased wholesale power market costs, the utility wrote after Sen. Ron Wyden (D-Ore.) voiced concern that customers are struggling to pay their electricity bills. 

PGE CEO Maria Pope responded to Wyden’s questions concerning increased electricity costs in Oregon in a Nov. 27 letter that described the immense growth the utility has seen in tech sector loads but stopped short of tying that development to the price pressures faced by residential ratepayers. 

The Oregon Public Utility Commission (OPUC) approved 40% in price increases for PGE customers from 2020 to 2024, an annual average increase of 8%, according to Pope. 

“These customer price changes over the last five years have primarily been driven by the rising costs to purchase necessary power from the open energy market to serve customers,” Pope wrote. “Power costs, which PGE has limited options to control and are necessary to maintain reliable service to customers, have nearly tripled in the past five years.” 

Pope’s response follows Wyden’s contention in a separate letter that PGE customers’ electricity bills have gone up by at least 40% since 2021, while nonpayment shutoffs have increased.  

“For folks that are walking an economic tightrope, balancing food and medicine bills with electricity prices, the rising prices are unsustainable,” Wyden wrote. 

The lawmaker acknowledged that efforts to modernize the power grid have partly contributed to the price changes but added that “it is concerning to see the cost of electricity rise at this rate in such a short time frame.” 

Wyden sent a list of seven questions to Pope’s office, requesting a response within 30 days. 

Pope got back to the lawmaker two days later, highlighting various factors that have contributed to the price increases over the past four years. The CEO pointed to recent investments in energy facilities and infrastructure, wildfires, heat waves and inflation, among other things. 

Energy deliveries in 2023 were 9.2% higher on a weather-adjusted basis than in 2019. In the 10 years prior, the utility saw growth of 2.8%. Industrial energy deliveries increased by 34.3% in the past five years, mainly driven by semiconductor manufacturing and data center segments, according to the letter. Over the same period, residential load grew by 5.2%, while commercial deliveries declined by 2.7%.  

Wyden asked if PGE has taken steps to limit the cost increases to those sectors that have driven the most growth in the past five years and to explain whether and why residential customers could be bearing the costs for that growth. 

Pope responded that rates for all customer classes are determined through OPUC’s public rate review process based on the utility’s cost of service to each class.   

“Existing regulatory frameworks will need to evolve to appropriately reflect how investments serve different customers and how costs are allocated given the changes in the new large load demands,” she wrote. “Collaboration with regulators, policymakers and stakeholders is essential to help address these new realities and to keep the price of electricity as low as possible for residential and other business customers.” 

‘Keep Pressing the Case’

Wyden also asked about costs not covered under the Inflation Reduction Act of 2022. The act aimed to cover 30% of the cost of new clean energy installations, the lawmaker’s letter stated. 

Pope responded that clean energy resources are not the main culprit behind rate increases, saying that “[t]he cost of power purchased on the market and through the Bonneville Power Administration (BPA) to serve customer demand, address capacity constraints or … fuel thermal plants tripled between 2019 and 2024.” 

“These costs are beyond the utility’s ability to control,” Pope added. “Over that same time, PGE’s own operating expenses underran the rate of inflation by 7%.” 

Doug Johnson, a spokesperson for BPA, told RTO Insider the agency “makes transactions at prevailing market prices and competes in the wholesale market as both a buyer and seller of energy and capacity.” 

“BPA, similar to PGE, has witnessed the value of these energy and capacity products fluctuate with a propensity to rise over the last few years as the demand for clean and reliable power and dispatchable resources has increased,” Johnson said.

“BPA was somewhat surprised to learn it had been singled out in the response letter,” he added.

Meanwhile, Wyden’s staff has contacted the OPUC to ask what else can be done to combat the increases, which exceed national averages, according to Hank Stern, a spokesperson for Wyden. 

“[Wyden] appreciates PGE’s responsiveness to his letter and in addition to the fresh discussions with the PUC about available options, will follow up with PGE to keep pressing the case for fair rates that Oregon consumers can afford,” Stern told RTO Insider. 

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Maryland Offshore Wind Plan Gains Final BOEM Approval

Federal regulators continue to advance offshore wind energy development, issuing a key approval for a Maryland proposal and smoothing the way for as many as six future projects in the New York Bight. 

The Bureau of Ocean Energy Management announced the decisions Dec. 2 and Dec. 3. They are the latest in a long series of such announcements by an administration that made building the U.S. offshore wind industry a priority — and among the last before the transition to a president who has pledged to shut down the industry. 

BOEM on Dec. 3 announced approval of the construction and operations plan for the proposed Maryland Offshore Wind project.  

It is the final BOEM approval needed for the plan. It had been expected after BOEM on Sept. 5 issued a record of decision in favor of US Wind’s proposal to place up to 114 wind turbines rated at up to 2 GW off the northern Maryland coast, near the Delaware border.  

The two-phase plan — called MarWin and Momentum Wind — has secured contracts with the state of Maryland for the offshore renewable energy certificates that will help make the project financially feasible. 

In prepared statements, the developer and an industry association made no mention of the Maryland Offshore Wind’s prospects after President Donald Trump returns to office next month. They also made no mention of the ecological benefits of offshore wind power, focusing instead on energy security and economic benefits, both of which are stated priorities for Trump. 

US Wind CEO Jeff Grybowski said: “This is a proud moment for US Wind. After more than four years of rigorous and robust analysis, we are thrilled to have secured this final BOEM approval. US Wind’s projects will produce massive amounts of homegrown energy and will help satisfy the region’s critical need for more electricity, all while supporting good local jobs. America can achieve energy abundance and put many Americans to work building the power plants of the future.” 

Oceantic Network CEO Liz Burdock said: “Today, Maryland Offshore Wind became the 10th approved commercial-scale project, another significant achievement for the U.S. offshore wind industry. The first project for the state of Maryland, it will deliver a host of economic benefits while helping to meet our nation’s growing energy demand. Maryland Offshore Wind will create American jobs by harnessing a strong, local offshore wind supply chain. US Wind has advanced plans to bring steel fabrication back to the old Bethlehem Steel facility in Dundalk, and the project will support a variety of other industries throughout its life cycle.” 

A day earlier, on Dec. 2, BOEM announced a record of decision identifying 58 environmental measures expected to be applied to projects proposed in the six New York Bight lease areas off the New Jersey-New York coast. 

Wind energy lease areas in the New York Bight are shown. | BOEM

BOEM’s simultaneous review of the six lease areas is a first-of-its-kind attempt to streamline the regulatory process for projects that potentially would have similar impacts and proceed on similar timelines, given their proximity to one another and given that all six leases were awarded in the same 2022 auction. 

As part of this process, BOEM completed a programmatic environmental impact statement in October. The groundwork BOEM is laying now does not confer any approvals, nor does it lock in the process by which future approvals would be granted. 

The six lease areas total nearly 500,000 acres and offer the potential for more than 7 GW of installed generation capacity. 

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$11B Transmission + Generation Plan Canceled in NY

An $11 billion package of transmission and renewable energy investments planned in New York has been canceled. 

The Clean Path New York (CPNY) renewable energy certificate (REC) contract with the state was terminated Nov. 27, and one of the partners in the venture said Dec. 2 the project itself has been abandoned. 

No reason was stated for the cancellation, but CPNY likely encountered the same delays and cost escalations that have bedeviled other energy projects in New York. 

CPNY was envisioned as a way to break the densely populated New York City region’s heavy reliance on aging fossil fuel power generation. 

It was to transmit 3.8 GW of power from 23 new solar and onshore wind projects in rural upstate New York south to the New York City area via a 175-mile underground HVDC line. 

Public- and private-sector officials announced in November 2021 that CPNY and the Champlain Hudson Power Express had been chosen for the new Tier 4 RECs designed to help decarbonize the downstate grid. 

After more than a decade in development, and with an expected price tag now in the $6 billion range, Champlain Hudson is under construction. (See Champlain Hudson Power Project Receives Landmark Delivery.) CPNY, which had expected to start construction in 2024 and enter service in 2027, had not yet been approved. 

CPNY was a public-private collaboration of the New York Power Authority (NYPA) and Forward Power, which is a joint venture of energyRe and Invenergy. 

New York State Energy Research and Development Authority (NYSERDA) notified the Department of Public Service on Nov. 27 that it and CPNY by mutual agreement had terminated the Tier 4 REC contract (Case 15-E-0302). 

The three-sentence notice provided no details, and neither did NYPA or Forward. 

NYPA Vice President of Corporate Communications Lindsay Kryzak said Dec. 2 via email: “The Clean Path project was a public-private collaboration in response to the Tier 4 RFP by NYSERDA. We worked alongside energyRE and Invenergy to continue moving Clean Path forward in the face of changing conditions related to the economics of the project. NYPA will continue to work on modernizing the grid and addressing New York State’s transmission needs to support its long-term goals.” 

Forward Power spokesperson Amy Varghese said via email: “energyRe and Invenergy remain committed to New York’s energy transition. As we continue to advance our portfolio of renewable energy projects across the state, we will evaluate solutions for addressing the largest transmission bottlenecks facing New York’s electric grid in order to deliver reliable and affordable power, good-paying jobs and clean air for the Empire State.” 

CPNY is the latest in a long series of casualties in New York’s legally mandated effort to green its grid. 

In June 2023, the developers of most of New York’s large-scale onshore and offshore renewable energy proposals sought to renegotiate their REC contracts because the cost of construction had soared after they locked in their compensation with the contracts. (See OSW Developers Seeking More Money from New York.) 

CPNY followed up with a petition for more money as well, arguing that it was facing the same economic pinch: 14 of the proposals that made up the generation side of the portfolio already held Tier 1 REC contracts, and the other nine were Tier 1-eligible. (See Clean Path NY Joins Calls for Inflation Adjustment.) 

The Public Service Commission rejected the developers’ request to renegotiate the contracts in October 2023 and CPNY subsequently withdrew its petition. (See NY Rejects Inflation Adjustment for Renewable Projects.)

Developers soon canceled the bulk of the REC contracts New York had signed. They were allowed to rebid their projects into subsequent solicitations, but the state’s portfolio of contracted renewables remains stunted a year later, and state officials expect to miss the 70% renewables by 2030 mandate, perhaps by a wide margin. (See NY Expects to Miss 2030 Renewable Energy Target.) 

Varghese did not provide a requested update on the status of the 23 generation proposals. 

They were not a batch of new proposals drawn up for CPNY. Rather, they were a collection of pre-existing proposals gathered into the CPNY portfolio. And cancellation of a REC contract does not mean cancellation of the project itself, though it almost certainly pushes back the timeline. 

Meanwhile, the complex Tier 4 mechanism itself is gradually taking shape. NYSERDA submitted an implementation plan Oct. 11, four years after Tier 4 was added to the state’s Clean Energy Standard. 

And a new state law gave NYPA a new role as a renewable energy developer in mid-2023, more than a year after its CPNY collaboration was chosen for a Tier 4 contract. 

NYPA is finalizing a strategic plan for 3.5 GW of wind, solar and storage capacity that it would develop on its own or in collaboration with the private sector. It has said the 40 proposals in the plan likely would suffer the same attrition rate as seen in the industry — 80 to 85% for early stage proposals and 30 to 60% for more mature projects. (See NYPA Enters Renewable Development with 3.5-GW Plan and NYPA Urged to Do More in New Renewables Role.) 

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LBNL Report Quantifies Resilience Benefit of Distributed Storage Systems

Installing solar-and-storage systems at customer homes can improve grid resilience, according to a new study from Lawrence Berkeley National Laboratory, which found they cut loss of load by a mean of 96%.

The study crunched the numbers on the value of mitigating loss of load and regional differences in outages that last more than 24 hours from around the country. It calculated a benefit-to-cost ratio (BCR) using those data against the cost of solar-and-storage systems, which found the resilience benefits alone justify an average of 14% of the costs of storage.

The actual resilience benefit to adding storage to solar varies significantly around the U.S., ranging from zero to 58% of the costs. Roughly half of the 2,519 counties studied have a BCR under 0.1, and just 12% of counties have a ratio greater than 0.3, the study says.

Those benefits grow with the frequency of extreme weather events leading to significant outages, a higher value of lost load (VOLL) and in scenarios with lower costs of storage, whether from tax credits or cheaper technology.

“The results demonstrate that, in most counties, resilience benefits alone are insufficient to justify the economic addition of storage to existing PV systems,” the study says. “The coinciding occurrence of higher frequency of resilience events, higher VOLL and lower cost can substantially increase average BCR, but these conditions apply to a smaller set of customers.”

Customers get more than just resilience from solar-plus-storage systems, such as cutting utility bills and leveraging grid services, the paper notes.

VOLL can vary significantly among individual customers, with residents that have medical devices that need electricity, vulnerable household members or sensitive equipment placing a higher value on it than others. The paper accounts for those varying needs with a sensitivity analysis.

The findings indicate that solar plus storage can alleviate the impact of resilience events on customers, especially in areas with a high number of such events.

“In the future, we expect climate change to increase the frequency of extreme weather events and potentially the frequency of interruptions,” the paper says. “Increased electrification of end uses intuitively suggests that customers’ average VOLL will increase: Fulfilling any needs will require electricity, with few substitutes available.”

With the regional disparity of areas more prone to outages and relatively higher VOLLs seeing more benefits from solar plus storage, the paper says customers in those areas should have affordable options to mitigate those impacts.

Utilities can maximize the grid and customer benefits of distributed solar plus storage by offering more granular outage information: detailing specific locations, durations and customer impacts, and making anonymized data public. They can also improve the quantification of VOLL, with the paper suggesting that utilities at least break down the value by customer class and location.

“Hosting capacity analyses and publicly available maps allow developers to target specific areas of the distribution system with value-adding resources,” the report says. “A similar approach could be developed for resilience value, in which a utility would integrate its outage management system data and granular VOLL estimates to quantify areas of the grid in which storage may have a high resilience value.”