The U.S. Department of Interior on Thursday announced a plan to make solar and wind energy development on public lands in Western states faster, easier and less expensive.
DOI said its proposed Renewable Energy Rule would reduce fees for such projects by about 80% and offer greater certainty to private-sector developers. It would codify reductions made by guidance last year and would expand them.
Publication of the proposed rule in the Federal Register on Friday kicked off a 60-day public comment period.
Under the proposal, the Bureau of Land Management would retain authority to hold competitive auctions but would gain expanded ability to accept non-competitive leasing applications it deemed to be in the public interest.
The Federal Land Policy and Management Act generally requires holders of rights of way to pay in advance the fair market value for use of public lands.
But the Energy Act of 2020 empowered BLM to make an exception to that rule — to reduce both acreage rents and capacity fees for existing and new solar and wind projects — if it makes certain findings, such as that the rates impose economic hardships or limit commercial interest in a competitive lease sale or ROW grant, or that the reduced cost is necessary to promote the greatest use of wind and solar energy resources.
BLM proposes to base the capacity fee on actual energy production of the installed equipment, rather than its nameplate capacity.
BLM also proposes to calculate the acreage rent for an ROW based on the per-acre value for pastureland calculated in the National Agricultural Statistics Service Cash Rents Survey, and to collect that acreage rent whether or not energy is generated on the land that year.
The five-year median per-acre value is currently $6.62 in the western states.
The capacity fee would be collected only if it exceeds the acreage rent; if a capacity fee is collected, no acreage rent would be due for the year.
One component of the capacity fee, the MWh rate — which is based on wholesale prices for the major trading hubs serving 11 Western states or on prices received by the ROW holder under a power purchase agreement — would be reduced by 80% until 2036 under the proposed rule.
In 2036, that would drop to a 20% reduction, but only for new ROWs and for existing ROWs up for renewal.
BLM expects that these reductions would particularly benefit smaller-scale projects or projects on the cusp of profitability.
BLM also is proposing capacity fee reductions tied to an ROW holder’s use of U.S.-made components, stimulating the domestic manufacturing sector by reducing the net cost differential between U.S.-made and foreign materials.
The Energy Act of 2020 established a minimum goal of authorizing production of not less than 25 GW of geothermal, solar and wind projects on public land not later than 2025. As of mid-2023, BLM has authorized more than 13 GW.
Members of Congress went to Moore County, N.C., on Friday to hold a field hearing on the substation attacks there in early December that knocked out power to 45,000 customers, and which remain unsolved.
Rep. Jeff Duncan, R-S.C., chair of the House Energy & Commerce Subcommittee on Energy, Climate and Grid Security said the hearing was part of an effort to gather information for possible changes in law to better protect the grid.
“There have been several grid security incidents that have occurred recently, that we’re examining as part of our oversight responsibilities,” Duncan said. “Within the last year, we’ve seen electrical transmission substations attacked in Tacoma, Washington, and right here in Moore County. Both of these attacks resulted in blackouts that affected tens of thousands of people for multiple days.”
The Colonial Pipeline was hit by a ransomware attack in May 2021, and the subcommittee is looking into all three attacks for lessons learned to see if critical infrastructure protections would benefit from new laws, he added.
William Ray, North Carolina Department of Public Safety’s Director of Emergency Management, said information-sharing laws could be updated so the government can better coordinate with private owners of critical infrastructure.
“The percentage of the Department of Homeland Security defined critical infrastructure sectors owned by the private sector is significant,” Ray said. “We must evolve and recognize that public or private, we need the members of those 16 sectors at the table and partnerships in which they can be fully transparent.”
The information-sharing protections in place now do not adequately support open, honest and transparent dialogue between the public and private sectors, he added. Both private sector and public information need protections, while also sharing between relevant parties.
“Current federal and state information sharing, and intelligence protections do not fully address the need for open dialogue, while protecting the parties engaged as well as limiting information sharing due to classification requirements,” Ray said.
While electric infrastructure has always been targeted by copper thieves, the industry has seen an uptick in incidents that can only be described as sabotage, said Tim Ponseti, SERC vice president of operations.
“Fortunately, the bulk power system has built into it extraordinary levels of redundancy, which enhances reliability increased resilience,” Ponseti said. “It takes widespread system damage, like from a hurricane or tornadoes or ice storms, or target attack, like what happened in Moore County, to leave a large number of people in the dark for an extended period of time.”
Critical Infrastructure Protection (CIP) Standard 14 was put in place after the Metcalf Substation attack in Northern California a decade ago and it requires the industry to ramp up physical security around the most important substations that have the biggest impact on reliable operations of the grid.
Since the Moore County attack, Duke Energy, which owned the substations attacked, has been working to ensure that any substation that would lead outages if knocked out also gets heightened protection, said Mark Aysta, Duke’s managing director of enterprise security.
“We’re shifting from a tiered ranking system, focused largely on an asset’s impact to the bulk electric system, to a tiered approach with a greater focus on potential impact to customers,” Aysta said. “It’s through this lens, we’ve identified opportunities to increase security and surveillance and we’re developing implementation schedules for this work.”
While some substations can go down and grid operators can just reroute the power to avoid any significant customer impact, that is not possible at other substations and Duke is increasing security around the latter, he added.
Duke has also identified electrical components that might have long lead times to manufacture and is working to make sure it has backups on hand to bounce back after any future incidents, said Aysta.
“But we understand that even with a robust strategy of deterrence and monitoring, no utility can completely eliminate the risk of an attack,” Aysta said. “That’s the reality of operating an electrical system that extends across nearly 100,000 square miles, and includes thousands of substations, and millions of components. It is why we firmly believe grid resiliency must be a part of the conversation.”
The same technology that can detect outages from storms, isolate problems and reroute power to restore service to customers can be used to mitigate the impact of an attack on the grid. Resiliency investments are a major part of the $75 billion Duke is spending on grid improvements for its electric utilities over the next decade, Aysta said.
A group of municipally owned utilities from across New England is seeking additional information related to the cost-of-service agreement between ISO-NE and the Mystic power plant in Massachusetts, arguing that the RTO has not provided adequate transparency to consumers.
ISO-NE entered into the two-year agreement with Constellation Energy in 2018 (ER18-1639) to address fuel security in the region. The Mystic generation station, the primary customer of the Everett Marine Terminal, was slated to retire when its capacity supply obligation expired in 2022. The Mystic agreement will keep the plant operating through the winter of 2023/24.
Everett is one of just three LNG import terminals serving New England and therefore is not subject to gas transmission reliability concerns. Mystic and Everett are both owned by Constellation.
Under the agreement, ISO-NE is responsible for the bulk of Mystic’s and Everett’s operating costs, which are eventually passed on to New England ratepayers. The agreement gives ISO-NE the right to perform detailed audits of Constellation’s compliance with the agreement to ensure that it is operating at the least cost to ratepayers.
FERC in 2018 ordered ISO-NE to “allow redacted versions of its reports to be publicly available and allow less redacted versions to be available to state commissions and other administrative nonparticipant bodies.”
The D.C. Circuit Court of Appeals denied a challenge to the agreement in 2022, but it did require FERC to order on remand that “interested parties may review and challenge the tank congestion charges during the true-up process.”
In a May 19 filing, a coalition of groups representing municipally owned utilities — including Massachusetts Municipal Wholesale Electric Co., Connecticut Municipal Electric Energy Cooperative, New Hampshire Electric Cooperative and Vermont Public Power Supply Authority (dubbed “Public Systems” in the proceedings) — argued that ISO-NE has not disclosed enough information for consumer groups to review and challenge the charges. They called for the release of a wide range of information related to the Mystic agreement.
The request said the agreement cost ratepayers more than $436 million in its first 10 months, “most of which appears to reflect the cost of rejecting or disposing of excess LNG procured by Constellation.”
As LNG costs skyrocketed this winter, the costs associated with the Mystic agreement dramatically increased, despite the fact that lower temperatures and natural gas prices reduced energy costs overall across the region. Much of the LNG procured by Everett was ultimately unnecessary to meet the region’s energy needs, with a large portion of the costs going toward managing the LNG storage tanks as new shipments came in. (See ISO-NE Market Monitor Reports Decreased Winter Energy Costs.)
“Given the magnitude of the charges passed through so far and how little information ISO-NE and Mystic have made public to justify them, we respectfully request that the commission act to require disclosure of information necessary to ensure that ISO is doing an adequate job of supervising Mystic’s fuel-management practices,” Public Systems wrote in their May request to FERC. “Requiring disclosure should help to enable New England ratepayers to take appropriate action to protect themselves against unwarranted charges.”
Public Systems’ letter included requests for monthly details about specific fuel supply costs related to the Mystic agreement, documents used to evaluate Constellation’s fuel supply plan and documents concerning the results of the monthly fuel supply audits conducted by Levitan & Associates Inc. (LAI) on behalf of ISO-NE. The letter also requested information regarding ISO-NE’s selection of LAI to conduct the audits, as well as the contract between ISO-NE and LAI.
In responses to this motion June 9, representatives from Connecticut’s Department of Energy and Environmental Protection, Office of Consumer Counsel and Office of the Attorney General expressed their support for the motion, while Constellation Energy opposed it, citing procedural issues and calling it “unnecessary and potentially harmful.”
ISO-NE proposed to make limited additional disclosures, smaller in scope than Public Systems’ request. It offered to disclose redacted versions of the fuel supply audits and hold three question-and-answer sessions for stakeholders with LAI. However, ISO-NE resisted the broad disclosure demands, arguing that “Public Systems have made no showing that the ISO’s exercise of its audit rights under the agreement has been deficient, that LAI’s auditing has been deficient or that charges incurred to date under the agreement are erroneous.”
The RTO in May released a public summary of the audits and the auditing rights of the RTO related to the Mystic agreement.
The Connecticut agencies argued that the audit summaries released by ISO-NE thus far remain inadequate, saying the disclosures “offer insufficient insight into how the auditor reached its conclusions, let alone facilitate an independent evaluation of whether the procurement strategies that have been employed, and their resultant costs, are just and reasonable.”
Conversely, ISO-NE argued that the audits commissioned by the RTO have been in line with the agreement and that Public Systems’ requests go beyond the level of disclosure required.
“The breadth of Public Systems’ requests here suggests an effort to ‘audit the auditor,’ a process that would enmesh the ISO in highly burdensome discovery over the audits’ conclusions,” the RTO wrote.
Constellation argued in its response that factors related to weather and global LNG prices are beyond the companies’ control and are not a valid reason to alter the existing agreement.
“It was always well understood that Mystic would manage its fuel supply to provide reliability and that such tank management could be costly,” Constellation wrote.
The company added that some of the information requested could lead to security issues, violate nondisclosure agreements and lead to the release of competitively sensitive information.
“The only ‘new’ fact here — the increase in global LNG prices that is the primary basis given by movants for their requested relief — was not of Constellation’s making and provides no basis for second-guessing the already audited tank-management decisions made by Constellation,” the company wrote.
Representatives of Constellation, ISO-NE and the Public Systems declined to comment for this article.
Audit Impartiality
Public Systems specifically asked for additional information about how ISO-NE selected LAI to audit Constellation’s fuel supply activities and charges, requesting disclosure of the RTO’s request for proposals to perform the audit along with the audit contract.
They added that ISO-NE has not disclosed “the basis on which ISO-NE determined that Levitan — which has testified repeatedly about the importance of retaining Everett and the need for Mystic to fund Everett’s operations — is sufficiently impartial to conduct the fuel supply audit.”
In its response to the filing, ISO-NE resisted disclosing additional information about the selection of LAI to perform the fuel supply audit.
“The ISO employed a request-for-proposal process that was typical of similar contracting efforts by the ISO, received multiple responses, and selected LAI based on qualifications and cost,” ISO-NE wrote. “The ISO respectfully submits that, in the absence of a showing that LAI is unqualified to perform the audits capably, these requests distract from the task of administering the” agreement.
Richard Levitan, president of LAI, said the disclosure of information related to the RFP and the contract is ISO-NE’s decision.
“If they’re comfortable, then we’re comfortable. If they’re not comfortable releasing it, we understand,” Levitan told RTO Insider. “I just would want to be sure that commercially sensitive information to Levitan & Associates is not swept up with such disclosure.”
Levitan dismissed concerns about the impartiality of the firm and said LAI is well positioned to identify any issues, given its specialization in fuel and renewable energy procurement.
“If after 30-some-odd years of business we failed the impartiality test, we would have long since shut our doors,” Levitan said.
Plainfield Township, Kent County could have a solar farm operating on a pond near its water treatment plant in a year’s time if all permits are approved and construction goes forward, said Cameron van Wyngarden, the township supervisor.
The 800 kW of energy generated by the floating farm would be used entirely by the water treatment plant, which serves the community of 31,000. Plainfield has agreed to buy the energy produced for 30 years from San Francisco-based White Pine Renewables, which will build and operate the plant. The township says the project could save it as much as $2 million over the next three decades.
White Pine already operates a 5-MW project at a wastewater treatment facility in in Healdsburg, Calif., that it says is the largest floating solar energy system in the country.
Van Wyngarden said both the township and the company had hoped to find a land-based site for the project, which would have been cheaper to build. But the dynamics of the township’s need and physical situation made the floating farm the only option available.
The township owns the 38-acre pond, which is left over from a gravel pit. It is adjacent to the water plant, and the plant uses the pond for its operations. There is no swimming or boating or other recreational use of the pond, he said.
Because the site is in a flood plain, the solar operation would have to undergo review by the state Department of Environment, Great Lakes and Energy. The plans will also have to be reviewed by the state Public Service Commission, Van Wyngarden said.
White Pine Renewables will handle that and other permits needed to get the solar field in operation. “We know how to produce the water and they know how to make energy,” Van Wyngarden said.
Solar and wind energy projects have generated controversy in many other Michigan communities, but Van Wyngarden said he has heard no comments opposing the project.
Van Wyngarden noted the project would not involve either cutting down trees or using farmland. Much of the opposition to renewable energy projects across the state has involved worries about losing farmland.
Significant decarbonization of the grid relying on solar, wind and storage is possible, but will be extremely expensive and may require updates to markets and compensation mechanisms, ISO-NE told its Planning Advisory Committee last week, reporting on the policy scenario results from its Economic Planning for the Clean Energy Transition (EPCET) pilot study.
The results highlighted the need for dispatchable generation as weather-dependent renewables come online and found that long-duration storage will become increasingly valuable in the coming decades.
“Longer duration storage becomes more valuable because it is more effective in shifting larger quantities of energy to the declining number of emitting hours,” said Benjamin Wilson of ISO-NE. “Seasonal storage, which could move large volumes of energy from the shoulder months to the winter, would be very useful but would be expensive to compensate.”
ISO-NE said that carbon reductions will become increasingly costly over time as the system decarbonizes.
“Subsequent additions of a given resource type have declining economic and carbon-reduction value,” Wilson said. “Emission reduction becomes an effort to procure new intermittent or energy limited resources to displace peakers.”
The RTO’s model still included some dispatchable fossil fuel generation in 2050, totaling about 1.4 million tons of annual emissions, as well as some generation from municipal solid waste, landfill gas and wood.
“When the majority of generating resources are intermittent and weather-driven, there will be conditions where dispatchable generation must be relied upon,” Wilson said. ““The worst-case reliability hours may not be the highest load hours. Instead, the indicator for worst-case reliability may be hours of dunkelflaute (dark wind lull) which coincide with moderate loads.”
The modeling did not include a significant generation role for low-carbon fuel alternatives, but Wilson said that future EPCET analyses could include these options. The presentation did not compare the energy costs of the carbon-constrained scenario to a business-as-usual case, which Wilson also said could be considered in the future.
The economy-wide costs related to climate impacts of unconstrained emissions are also projected to be extremely expensive — a 2022 white paper by the White House Office of Management and Budget estimates that the financial impacts of climate change to the U.S. could reach $2 trillion annually by 2100, or a 7.1% reduction in federal revenue.
Future Capacity Requirements
ISO-NE also presented an overview of the results from its installed capacity requirement (ICR) and operational capacity analysis to the Planning Advisory Committee on Thursday.
The ICR is the minimum amount of installed capacity needed to ensure grid reliability for the region, while the net ICR — used to determine the amount of capacity procured by the RTO in the Forward Capacity Auction — equals the ICR minus the Hydro-Québec Interconnection Capability Credits.
Projecting out through 2033, the RTO expects the Net ICR, along with the gross peak load, to slightly increase as electrification increases. ISO-NE said this increase in electrification will cause elevated winter reliability risks in the early 2030s.
“With the growing load, primarily due to the increasing electrification forecasted in the 2023 CELT Report, we observed some loss of load risk during the winter, particularly during the later years of the forecast cycle,” said Helve Saarela of ISO-NE.
“Assuming that the amount of CSOs (31,370 MW) procured in FCA 17 stays in-service and assuming additional Sponsored Policy Resources, there should be an adequate amount of capacity to meet the resource adequacy needs,” Saarela added.
Asset Condition Projects
Also at the PAC meeting, Eversource outlined plans to spend approximately $577 million on three asset condition projects:
Eversource plans to replace two underground 115 kV cables — covering about seven total miles — near Southwest Hartford, Connecticut, with a projected cost of $301.6 million and an in-service date of late 2026. Eversource said the replacement would reduce hazards related to deteriorating infrastructure, improve reliability and increase capacity.
The utility company proposed to spend $269.9 million to replace over 800 wood structures with steel structures across 10 115 kV transmission lines in New Hampshire. Many of these structures are relatively new laminated wood structures installed between 2000 and 2014. Eversource said this is the final phase of the company’s Laminated Wood Structure Replacement Program and said the new structures would increase resilience and reliability and enable larger conductor sizes in the future. The projected in-service dates ranged from early 2024 to the second half of 2025.
Finally, Eversource said it plans to spend $5.5 million to replace 15 relays at a substation in Deerfield, Massachusetts, saying suppliers are no longer making replacement parts for the equipment. The projected in-service date is the first half of 2025.
NEW YORK — With individual project budgets reaching into nine and 10 digits, financing often is front and center in discussions of the clean energy transition.
And it was the leadoff topic Wednesday, as the Northeast Chapter of the Energy Bar Association convened its annual meeting in Manhattan.
The confluence of headwinds and tailwinds in the early 2020s — war, contagion, inflation, policy support, the end of cheap capital, massive tax credits, massively complicated rules for those tax credits, delay upon delay — makes for interesting times.
Kurt Strunk, managing director of National Economic Research Associates, said the fundamentals are the same as always: “What’s really needed is strong economic governance and reliable institutional foundations … The good news is, the institutional structure is there.”
The traditional formula to finance a power plant — “an airtight offtake contract with a creditworthy counterparty” — is still a winning combination, in his opinion.
“It’s true that the amount of investment needed to affect the energy transition is daunting,” Strunk acknowledged.
The extensive tax credits of the Inflation Reduction Act were intended to accelerate the U.S. clean energy transition and help create a domestic manufacturing base to supply it. A secondary beneficiary has been the army of legal and financial experts putting together deals to leverage those credits.
Financing the Transition
“Tax equity bridge financing has been the flavor of the year so far,” said David Avila of Paul Hastings LLP. “Everyone, with the IRA coming into place, is trying to take advantage of the ITCs and PTCs. That has really increased demand for the tax equity, which is now completely outstripping the supply.”
He said he has spoken recently with banks that have traditionally worked only in debt but are now looking to move into tax equity. “I think that’s going to be something we see evolving over the next couple of years.”
Also, Avila said, banks are getting more comfortable closing on just a letter of intent with a credit-rated entity, rather than the signed tax equity contribution agreements traditionally required. That puts much more scrutiny on the sponsors themselves, he added.
“We’re spending a lot more time structuring these deals than we ever have before. It’s a lot more problem-solving and constructing the financing.”
One aspect of the IRA — the domestic content adder — is problematic at this stage, Avila said. With U.S. manufacturing still ramping up or even still on the drawing board in mid-2023, it’s entirely possible a project planned now will have less domestic content than originally expected once it’s completed, years in the future. If the domestic content adder was factored into the financing but the project is disqualified from receiving it, there’s suddenly a big hole in the financials.
Another problem Avila is seeing more than in the past is project attrition.
If interconnection upgrade costs are spread between several projects in the queue, and some of those other projects drop out of the queue, the entire cost falls on the surviving projects, blowing out their contingency budgets.
“We’re getting a lot of questions from lenders … asking us to go into the dockets to see which interconnection providers have had these issues,” Avila said.
Vikram Bakshi, managing director at Skyline Renewables, said he’s been working in renewable energy since 2006 and sees enormous opportunity in 2023.
“In terms of market trends, couldn’t be more optimistic,” he said. “We see trillions of dollars of opportunity — not just cleaning up the grid, but if you look at decarbonization of the rest of industry, the numbers are enormous.”
Renewables are the cheapest form of generation, there’s regulatory support for them, the IRA creates tailwinds and corporations want to boost their ESG profile with green energy, he said.
“I’m not sure what obstacles and headwinds you’re talking about, Kurt,” Bakshi added, drawing a laugh from the audience.
Supply chain, financing, interest rates and indexed pricing, Strunk replied.
Bakshi acknowledged short-term supply chain constraints, cost increases and delays and uncertainty about IRA guidance.
“But that’s going to be sorted out. We’re in no rush,” he said.
Bakshi added an important detail: Skyline is not in early stage renewable development. It typically steps in at the notice-to-proceed or the commercial-operations-date stage.
Alex Stein, senior counsel at the New York State Energy Research and Development Authority, added the perspective of a governmental entity leading a clean energy transition and awarding billions of dollars’ worth of contracts to carry it out.
NYSERDA has built some flexibility and adaptation into its clean energy solicitations. Earlier rounds allowed developers to bid a fixed price for renewable energy credits or a strike price indexed to the zonal energy and capacity price.
It is not a perfect hedge, Stein said, but it insulates against a lot of volatility.
The most recent solicitations have the option of an inflation adjuster, he said.
The period from proposal to start of construction is particularly long in New York. Developers of most of the pipeline of clean energy projects the state’s leaders boast about had locked in their compensation — but not their input costs — before the tumultuous events of the past three years.
Developers of much of the onshore portfolio and almost all the offshore portfolio this month petitioned for the same inflation index as NYSERDA is offering newer projects, saying they can’t obtain financing without it.
Stein did not touch on the petitions, which await review by the state Public Service Commission.
But he said NYSERDA took steps to recoup some of the windfall offshore wind developers might receive through IRA tax credits: “We see it as a way of sharing the potential upside of this and also reflecting the uncertainty that remains.”
Another provision in the latest offshore solicitation allowed developers to recoup higher-than-expected interconnection costs and required them to turn over most of the savings if those costs were lower than expected.
It is an evolving process, Stein said: “I think we can brainstorm on how to iterate this in the future.”
Role of Natural Gas
It was observed Wednesday that practitioners of energy law have tended to focus either on electrons or molecules — electricity or gas — but that those lines are blurring because natural gas has become an important fuel for generating electricity and electricity will be used to generate another gas: hydrogen.
Chris Smith, regulatory counsel to the Interstate Natural Gas Association of America, said natural gas has a critical role to play in the power grid for many years to come.
“There’s this perception that for the time being we can just gut it out because eventually we’re going to be transitioning to more renewable resources … we can kind of just squeak by the next couple years and then this thing will work itself out,” he said.
“Admittedly biased view, but I think for a lot of these problems you are going to need additional natural gas pipeline infrastructure — we don’t have enough now and we’re going to need more in the future,” Smith said.
Brian Fitzpatrick, principal fuel supply strategist at PJM, agreed.
He said gas fuels almost half of the RTO’s installed generation, but not all the generators have a locked-in supply. “About half of that has some firm level of transportation associated with it,” he said. “In an ideal world we’d love that to be 100%, but it’s not available — most of the large pipelines in this system are fully subscribed.”
Fitzpatrick said PJM is looking at 40 GW of potential fossil fuel retirements by 2030, mostly coal, without a similar amount of replacement capacity coming online in the same period. There needs to be multiple gigawatts of new renewable energy for each gigawatt of coal retired, but that is not happening, he said. Only about 8 GW of natural gas is in the queue.
“That mismatch can’t continue — otherwise we’re facing a significant reliability concern going forward,” he said.
PJM is gathering stakeholder input and intends to address this with a FERC filing by the end of October.
The West’s summer reliability outlook is better than it has been the past few years, but shortfalls could arise if new resources fail to materialize or imported electricity does not flow as expected, WECC analysts said last week in a technical session that preceded the organization’s Board of Directors meeting.
“Yes, we are improving,” WECC principal analyst Matthew Elkins said. “We’ve delayed retirements. We’ve expedited new resources online. Things are getting better in the near term.”
However, with supply chain holdups, fuel constraints and other problems, “I think we’re just kicking that can down the road,” Elkins said.
With more than 4,000 MW of coal-fired generating resources expected to retire by 2025, the supply chain issues need to be resolved and large amounts of new clean energy and storage resources need to be built if the West is to avoid further shortfalls, he said.
“We need to keep track of this,” Elkins said.
In its 2023 Summer Reliability Assessment, NERC said resources in the Western Interconnection are sufficient to support normal peak demand, but warned that a wide-area heat event could create problems for multiple subregions that normally rely on regional transfers to meet peak demand when solar production falls off.
Elkins discussed those potential pitfalls and others in the technical session.
WECC analysts developed a matrix that shows hours at risk of shortfalls without new resources or imports in its four planning regions: California-Mexico, the Northwest, the Southwest and Canada.
In California-Mexico, there should be minimal loss-of-load hours if imports are not limited and all new Tier 1 resources come online this summer. Without those resources or transfers, the loss-of-load hours increase substantially, WECC’s analysis shows.
The same is true to a lesser extent in the Northwest and Southwest, WECC predicts.
Up to 13 GW of new generation and storage resources are planned to come online in the Western Interconnection by the end of this summer, but supply chain disruptions could undermine those plans, WECC says. (See Western Plan to Add 13 GW by Summer Comes with Risks.)
Most of the new resource additions will be solar, battery storage and wind, with some natural gas and biogas generation.
Last year, new solar installations in the West fell nearly 3 GW short of expectations because of tariffs on solar panels from Southeast Asia and supply chain constraints.
Many battery components still come from China, which has experienced COVID-related supply chain disruptions, as well as increasing tensions with the U.S. that could affect trade.
Planned battery installations last year fell short in WECC’s Northwest and Southwest regions, but not in California-Mexico, where the new batteries added to the grid exceeded expectations.
Through the end of 2023, more than 25,000 MW of new resources are planned to be installed. Elkins called the figure “historical.”
“We’ve never been over 10,000 MW,” Elkins said. “We’ve never built that much. This is two and a half times what we’ve actually built in the past.”
Whether most of those planned resources get built remains to be seen.
NEW YORK — The Northeast Chapter of the Energy Bar Association held its annual meeting last week in New York, a state that’s keeping attorneys practicing in the energy sector particularly busy.
The state’s leaders boast of a nation-leading climate protection plan. Other states make similar claims, but New York would surely land at or near the top of any objective ranking.
It’s a hugely complicated and expensive undertaking, with many people working to make it happen.
New York State Public Service Commission Chair Rory Christian, keynote speaker at Wednesday’s meeting, compared law to electricity: Society relies on both, expects both to function perfectly, but gives little thought to how they actually work.
The PSC has as its core mission maintaining affordable, safe, reliable, secure utility service, he said. But the passage of New York’s landmark Climate Leadership and Community Protection Act in 2019 gave the PSC a central role in climate protection as well.
And it’s taking steps every day to reduce greenhouse gas emissions from one of the largest sources: power generation.
“The results of this work will be seen in the form of changes to how our society uses and relates to the energy it needs to thrive,” Christian said.
“Each of you in this room today, in some way, will be called upon to address these concerns. Though you may not be climate lawyers by name, every lawyer in this room, in one way or another, will be working on climate change. Your clients’ needs will be increasingly driven by impacts of climate change, and it will be up to you to help support them through those efforts.”
Christian set the stage for a roundtable discussion later in the meeting about transmission infrastructure in New York, noting that PSC’s effort to reduce emissions from generation is only part of decarbonizing the power sector.
“Transmission is incredibly important because it’s integral to be successful in what we’re doing. The system we built — one based on large, central power plants — requires a different kind of transmission infrastructure than the one we envision in the future, one that’s largely decentralized, distributed, relying on smaller, more intermittent resources,” he said.
“Building out this transmission infrastructure is going to be a critical component in our efforts to meet our goals. Accomplishing this is going to require a multipronged effort above and beyond the vehicles available to us.”
Roundtable Discussion
Moderator William Hollaway, of Gibson Dunn & Crutcher, opened the roundtable on a positive note: Why have there been so many success stories with transmission infrastructure development in New York?
Asha Gandhi, a senior vice president at energyRe, offered four reasons: a policy that sets a very ambitious target for renewable energy generation and recognizes transmission’s role in that; frameworks for public-private partnerships; a structure for revenue sourcing; and a streamlined permitting process.
EnergyRe is part of one of the largest clean energy projects in the nation, partnering with the New York Power Authority and Invenergy on Clean Path NY, which entails 3.8 GW of wind and solar power and a 175-mile HVDC line to bring that electricity to the New York City region at an estimated $11 billion cost.
Other questions and responses:
Q: What have you learned about stakeholder engagement?
A: It is critical before the project starts planning, while it is being built, and then during its 40-year lifespan, said Donald Jessome, CEO of Transmission Developers Inc.
“If you don’t do stakeholder engagement, your project will never get built,” he said. “Somebody else will tell your story, and they’re not going to tell your story the way you want it to be told.”
TDI is building the Champlain Hudson Power Express from Quebec to New York City. Jessome recalled there was opposition to the project from environmentalists for how they feared it would impact the Hudson River. So, he met with them, and brought along a piece of the cable he proposed to bury below the water. Their opposition dissolved when they saw how small it was.
A: Stuart Nachmias, CEO of Con Edison Transmission, said NIMBYism is alive and well. There’s widespread support for clean energy, he said, except when its infrastructure is in somebody’s backyard.
Getting feet on the ground and getting acquainted with the people who live there can help a lot, he said, describing a field meeting with a developer who pointed out the resident who raised llamas, the neighbor who baked cookies for the crew, the farmer who asked that the construction schedule be rearranged, and the person who was mollified by a tower being relocated 10 feet.
“Things like that make a difference,” Nachmias said. “It doesn’t mean that you won’t get resistance — you still can. But it can help reduce resistance and help gain support.”
Q: How do you address and protect disadvantaged communities in the development process?
A: EnergyRe is committed to spending over $300 million on community benefits, Gandhi said. It will bury the Clean Path NY line for its entire length, and rerouted it where necessary.
A: NYPA Development President Phil Toia said the state-owned utility has an active environmental justice group embedded in the community and in the development teams, working to be sure concerns are heard and solutions are sought.
A: Nachmias said it may be impossible to route a power line away from a given community, but that line will be carrying clean power and will be accompanied with community benefits such as vocational training.
A: Jessome said a point of pride for TDI is converting the site of a fossil-fired power station in a New York City pollution zone into the terminus for the CHPE line.
Q: What impediments exist to building all the transmission and generation that needs to be built?
A: Nachmias said there need to be transmission corridors rather than lines, especially for something like offshore wind.
“We didn’t build the highways one lane at a time. The real way you’re going to not get community support is to put one line in, and then come back and do the second line, and come back and build the third line. That’s a recipe for failure.”
Developers are not only not incentivized to build extra transmission, but they are also disincentivized, he said. Generation should be built separately from transmission, he added, so that first users of the transmission asset need not bear the entire cost of something that probably will outlive their generation asset.
“We’re going to get one chance to get it right,” Nachmias said.
A: Gandhi said energyRe would tend to agree that the process to bring offshore electricity onshore is not efficient, and the European model has been to build out the grid first, then allow interconnection.
Q: What if a latent bottleneck is created in the first wave of projects that will manifest itself as a barrier to later waves?
A: “That’s the entire point of running all the NYISO studies,” Gandhi said. “Hopefully, what we know, we’re managing. Being the first is not always the easiest.”
A: Toia said the state’s 2040 goals are very clear. “So that’s the North Star here, directing us where we’ll go. Will we get everything right? Probably not. But we have a clear direction of where we are headed,” Toia said.
Current NYPA transmission projects are addressing decades-old congestion, he added. “So, it’s not that we were perfect before, either. That’s just the nature of the system.”
Q: Where do you look for signals and guidance?
A: Economic factors, market dynamics and the policy decisions that drive them, Gandhi said.
A: Reliability is a fundamental guiding principle, Nachmias said.
A: Demand-side signals are very important, but we still need supply, Jessome said.
Part of the Solution
Hollaway closed the session with the thought that the processes discussed Wednesday need to extend beyond policymakers, energy developers and attorneys to the millions of people who ultimately will reap the benefits of the decisions being made — as well as foot the bill.
The need, in other words, is for people to realize they are part of the solution.
“That might mean land use, but it also means contributing into the pot to help defray the cost of these things,” he said.
The increasing visibility of electric cars and other tangible signs of change may help this happen, he said.
“As people see that, maybe they’ll start to say, ‘You know, I AM part of this transition, and I do have a responsibility to pay, I am a beneficiary,’” Hollaway said.
“Maybe the whole beneficiary-pays thing will become less abstract once people are actually seeing how this stuff hits home with them.”
MADISON, Wis. — The cost estimate for MISO’s and SPP’s package of 345-kV lines meant to facilitate the interconnection of generation at the seams has nearly doubled, the RTOs have said in the past week.
The portfolio’s costs have climbed from $1.1 billion to $1.9 billion because of the mounting cost of materials and labor and the transmission owners providing more precise routing options.
Aubrey Johnson, MISO’s vice president of system planning, updated the joint targeted interconnection queue’s (JTIQ) cost estimate during the grid operator’s Board Week in Madison, Wis., last week.
The increased amount was included in an application led by the Minnesota Department of Commerce and The Great Plains Institute for Department of Energy funds from the agency’s Grid Resilience and Innovation Partnerships program. If successful, the JTIQ portfolio could receive up to 50% funding match from the federal government. (See DOE Clears JTIQ Projects to Proceed with Funding App.)
MISO said the first cost estimate was theoretical and two years old.
“The 2023 JTIQ application to DOE reflects a higher end, broader scope, cost estimate for matching federal funds, and it is not directly comparable to the 2021 planning-level cost estimates,” MISO spokesperson Brandon Morris said in an emailed statement to RTO Insider. “Since 2021, we have also seen inflationary pressures and supply chain uncertainty.”
“Developers are having heartburn about the cost increases and would like to have some understanding and parameters around the increases,” Clean Grid Alliance’s Beth Soholt said during an Advisory Committee meeting Wednesday.
She urged MISO and its transmission owners to institute “checks and balances,” given the JTIQ’s proposed cost allocation that has generation developers responsible for 90% of costs and load picking up the remaining 10%.
MISO said it will further update stakeholders on the JTIQ’s application for DOE funding at a June 27 combined Planning Advisory Committee and Regional Expansion Criteria Benefits Working Group meeting.
During an SPP Seams Advisory Group meeting June 9, the RTO’s Aaron Shipley said staff is reviewing the cost increases and developing a more detailed breakdown of the rising prices.
“Whereas originally we were working on a conceptual cost estimate basis, as we get closer to it, we find those cost estimates from the TOs themselves,” he said. “Some of that [is] inflation impacts … but also more accurate routing of assessments, materials’ costs, the construction timeline [and] supply chain concerns. Those type of items really drove some of that cost [increase].”
Shipley said had the applicants’ DOE application used the $1 billion estimate, they would have been limited to up to half that amount should the agency award any funds.
The Southeast’s solar capacity will more than double by 2026, according to the Southern Alliance for Clean Energy’s (SACE) sixth report on solar energy development.
The report released Wednesday forecasts growth to 40 GW of capacity by 2026, more than double the 18.8 GW claimed last year. Available watts/customer (W/C) are expected to increase as well, from 580 last year to 1,217 in 2026. SACE Executive Director Steve Smith described this rise as a “generational transition” in more than one sense.
“You have to be part of the clean energy generation, both in a generational sense where each and every one of us are part of the generation to actually seize this moment and create change,” Smith said. “But then also we’ve got to get more literally physical clean energy generation on the ground.”
This growth, the report says, is due largely to two federal moves: The implementation of the Inflation Reduction Act (IRA); and a two-year moratorium on import duties from Vietnam, Cambodia, Thailand and Malaysia that “helped the U.S. solar industry regain its footing after an extended supply chain disruption.”
Southeast Solar Forecast by State | Southern Alliance for Clean Energy
Within the IRA, production and investment tax credits were returned to their full valuation of 30% and extended out to 2032, which “provided certainty into the market that the market really needs,” said Bryan Jacob, SACE’s solar program director.
The IRA also contains a $9.7 billion grant for rural electric co-ops, which Jacob said may be “the most transformational program for rural America since the Rural Electrification Act itself, back in 1936.”
The steep increase in available solar capacity in the next four years will not be evenly borne by the states in the Southeast, the report showed. Driven by policies such as solar base rate adjustment, said Jacob, Florida will increase its capacity to more than 17 GW by 2026, “almost as much as the entire Southeast region had last year.”
North Carolina, Georgia and South Carolina are also projected to increase their capacity dramatically, with Georgia slated to overtake North Carolina in both total capacity and watts/customer by 2026. Alabama, Tennessee and Mississippi “continue to fall far short of other Southeast states in both installed capacity MW as well as watts per customer (W/C) solar ratio,” the report said.
When asked to elaborate on the latter projection, Smith said he has not seen these states’ utilities “look at solar as a workhorse resource yet,” adding that many utilities are “inappropriately planning for what the future is unfolding to be,” and “making the wrong bets” on fossil fuels.
Sunblockers and Sunrisers
SACE’s report highlights several of these lagging utilities as “Sunblockers” — utilities with more than 500,000 customers with a four-year projected W/C ratio less than the Southeast’s average for last year (580).
Alabama Power and the North Carolina Electric Cooperative remain on this list from last year, at 331 and 197 W/C respectively, with PowerSouth joining them at 169 W/C. While Tennessee Valley Authority and Seminole Electric “remain considerably below the region averages,” at 658 and 600 W/C, the report said, they are not quite Sunblockers technically.
The opposite category also exists: “Sunrisers,” or the seven utilities with the largest projected increase in W/C solar ratio. Walton EMC, projected to increase its ratio by more than 4,000 W/C, retained its large lead. The second-largest increase was 1,564 W/C by the Knoxville Utilities Board. New to the Sunrisers list is Santee Cooper, due both to the utility’s own plan and commissioned solar development. The Sunrisers list is not constrained by customer base size as is the Sunblockers list.
However, these projections are not set in stone, Jacob said, as “the most important contributor to the forecast is integ resource plans (IRPs) that we have access to.” Because of the IRA’s recency, some utilities “haven’t had a resource planning process since August of last year, when the Inflation Reduction Act was signed.”
Georgia Power, for example, will not have a new resource planning process until 2025, while Duke will file its first IRPs aligned with its new Carbon Plan on Aug. 1and Sept. 1 for South Carolina and North Carolina.
So, while some growth is reflected in the forecast, Jacob said, “We’re gonna see a lot more for kind of the back half of the decade. That being said, the current forecast out to 2026 is already super bullish.”
