Search
December 27, 2024

Posted on

Order 881 Timelines Need Explaining, FERC Says

Continuing its recent trend, FERC on Thursday found that another set of transmission providers had mostly complied with Order 881 but failed to adequately explain their timelines for calculating and submitting ambient-adjusted line ratings (AARs), as the order requires.

The transmission owners and operators that FERC told to submit additional compliance filings for AAR timelines included ISO-NE and its participating transmission owners (ER22-2357, ER22-2467), MISO (ER22-2363), Idaho Power (ER22-2292), Public Service Co. of New Mexico (ER22-2335), Puget Sound Energy (ER22-2361) and Golden Spread Electric Cooperative of Amarillo, Texas (ER22-2161).

The decisions followed a similar grouping of orders in April in which FERC found that a handful of transmission providers, including NYISO and Arizona Public Service, had not complied with Order 881’s timeline requirements. (See FERC Approves Batch of Line Ratings Compliance Filings.)

In each of the cases, FERC acknowledged that software and other implementation tools are still being developed, so that “timelines may not be determined until closer to AAR implementation and that additional time may be necessary to comply with this requirement.”

Order 881 takes effect July 12, 2025. The commission gave the parties until November 2024 to submit further compliance filings.

Issued in December 2021, Order 881 requires transmission providers to employ AARs for short-term transmission requests of 10 days or less on lines affected by air temperatures. Seasonal ratings will be required for long-term service.

The commission said the current practice of rating lines based on conservative assumptions about worst-case weather scenarios has caused underutilization of available transmission capacity and driven up wholesale electricity prices. (See FERC Orders End to Static Tx Line Ratings.)

FERC did not specify timelines by which transmission providers must submit their AARs. Instead, it said transmission providers “already manage similar timing issues” for load forecasts, renewable generation and generation bid deadlines.

“It may be that the deadlines for AAR calculation and submission are not significantly different from existing deadlines for submission of updates to generation supply offers and load,” FERC repeated in its recent orders.

FERC found additional compliance problems in some of Thursday’s cases.

Citing Order 881’s requirements, it directed ISO-NE to revise its filing to “specify that transmission service at ISO-NE’s seams use AARs as the basis for evaluation for near-term transmission service requests or explain why it should not be required to do so.”

The commission found that proposals by ISO-NE and its transmission owners related to a transmission line ratings database fell short.

In MISO, FERC instructed the ISO to address “whether or how its proposed tariff language requires MISO to use updated AARs” in its day-ahead and real-time markets, including reliability unit commitment and look-ahead commitment processes, as required by Order No. 881.

It gave MISO 60 days to update its filing.

MISO has said it plans to function as a ratings clearinghouse for real-time and forecasted AARs by gathering “all known line-rating information, including from neighboring reliability coordinators,” and sharing that information with interested parties.

Late last year, MISO said its top priority for Order 881 compliance was creating an interface for its transmission owners to submit variable ratings starting as soon as the fourth quarter of 2023. Two of its transmission owners (TOs) started AAR pilot programs in 2022, with more to follow this year.

The RTO has said it’s “ready and able to add additional real-time AARs as TOs are ready.” (See MISO, Members Debate Deploying AARs.)

Posted on

MISO: Sufficient 2023/24 Auction No Cause for Comfort

MADISON, Wis. — MISO executives again emphasized that this year’s capacity auction results aren’t indicative of the resource adequacy risks the system is going to confront in coming years or even within a few weeks.

Executive Director of Market Operations J.T. Smith said members’ reaction to last year’s high prices and MISO’s new seasonal design helped MISO achieve capacity sufficiency in the 2023/24 planning year that began June 1. (See 1st MISO Seasonal Auctions Yield Adequate Supply, Low Prices.)

But he issued a warning that the results shouldn’t leave MISO complacent.

Smith said from last year to this year, members cut back on their load forecasts, deferred baseload generation retirements, and some units left PJM for the MISO capacity construct.

“The $10/MWh summer number does not say all is well,” Smith warned the MISO Board of Directors at a June 13 Markets Committee meeting. “We’re not fixed. We still have a lot more to do in making sure this market sends the right price signals.”

Senior Vice President of Markets Todd Ramey said the approximate 5-GW supply improvement over last year in the auction comes down to factors that are not “repeatable or sustainable.”

Smith said MISO has more to do to value capacity in accordance with its reliability contribution and incent new generation. He said adding the seasonal component this year was an important step.

“As an operations person, I’m interested in how the seasonal construct lowered summer pricing. That’s a surprising outcome. I feel much more confident in where we’re moving versus where we’ve been,” he said.

But Smith said over the summer, MISO “may have to lean on non-firm imports all the way to load management” on the chance that the nation experiences a prolonged, widespread heatwave that drives up load. He said if MISO’s previous forecasts for heat concentrated in June and a cooler July and August pan out, “it should be an easy summer as it was an easy spring.” (See MISO: Little Firm Capacity to Spare This Summer.)

MISO Independent Market Monitor David Patton said under more realistic summertime modeling using historic generator availability, he foresees the potential for negative reserve margins this summer; however, he said MISO’s vast import capability means the RTO likely will be resource adequate in a heatwave.

“With the seasonal capacity market, I believe we’re creating stronger incentives for resources not to schedule outages in the summer,” Patton said.

However, he said MISO might be undercounting de-rates in high temperatures because some thermal resources must cut output to avoid discharging warm water into rivers at certain times. He also said MISO’s long-lead resources aren’t realistically available to respond in time when needed.

“These aren’t the greatest scenarios to be under,” he said.

Otherwise, MISO oversaw an operationally straightforward spring, with an average 69-GW load. Smith said real-time prices were down from an average $57/MWh in 2022 to $26/MWh mostly due to a stabilized gas market.

“You can see the energy prices dropped by half because gas prices dropped by two-thirds,” Patton said.

Patton said the nation’s gas storage is 20% higher than usual because the mild winter allowed production to continue while fuel demand dipped. He also said the lower gas prices in spring mean that MISO’s coal resources were back to earning very little profit, “somewhere in the neighborhood of $5/MWh.”  Over 2022, coal generation was unusually profitable because natural gas prices shot upward.

Posted on

MISO Awaiting Construction on 40 GW of Approved New Resources

MADISON, Wis. — MISO membership and executives last week discussed how to hasten the construction of more than 40 GW of generation projects that have permission to connect to the grid but haven’t been built.

At MISO Board Week June 13-15, MISO leadership repeatedly mentioned that the system is sitting on 42 GW of unbuilt resources that have cleared the interconnection queue and would shore up deteriorating reserves.

During a resource adequacy roundtable at the June 14 Advisory Committee meeting, MISO Director Todd Raba asked how MISO might spur construction on those projects with signed agreements.

Sustainable FERC Project’s Natalie McIntire said supply chain issues are part of the equation, but she said many projects are waiting on future regional transmission projects.

“These generators don’t have a highway to market, so they’re not being built. So, we have a variety of issues that are coming to play here,” she said.

Sierra Club attorney Greg Wannier agreed new transmission is key to easing resource adequacy concerns.

Travis Stewart, representing the Coalition of Midwest Power Producers, said many of those paused generation projects were proposed three to five years ago in a pre-COVID world and have since been subject to macroeconomic challenges. He said the projects are emerging from “COVID limbo,” with developers now figuring out how they can be adjusted to be profitable.

Wisconsin Public Service Commissioner Tyler Huebner said the faster MISO can get generation projects through the queue and connected, the sooner the footprint’s resource adequacy concerns can be downgraded.

During the June 15 board meeting, Senior Vice President of Markets Todd Ramey said MISO is surveying the developers behind the interconnection projects. In some cases, the projects have languished with generator interconnection agreements that are now two years old.

“Bringing new resources online is an important part of the reliability imperative,” Ramey said. He added that MISO is ready to support the developers to lessen “bottlenecks” to building.

In a public comment session, John Norris, former chair of the Iowa Utilities Board and former FERC commissioner, chastised MISO for not getting a jump on major planning sooner to bring new resources online.

He said MISO is wasting its time proposing new restrictions on which generation projects can enter its interconnection queue when new transmission routes would allow generation projects to proceed.

Norris said when even his teenage son is aware that a “gazillion” gigawatts of renewable energy are stalled in interconnection queues because the grid is insufficient, it’s a good indication that the public is increasingly aware that new transmission is foundational to the clean energy transition.

Norris said it’s appalling that there’s now going to be at least a “quarter century” of lag time between Entergy and other southern entities forming MISO South and MISO overseeing an expanded transfer built between MISO Midwest and South. Norris was relying on an average decadelong planning and construction phase for major transmission for the 25-year estimate. MISO’s center-of-the-country position means it has a distinct duty to ensure that transmission is being built sooner, he argued.

In the long run, MISO is still banking on a flock of new renewable sources — and a host of new requirements to govern them.

Scott Wright, MISO | © RTO Insider LLC

Executive Director of Resource Planning Scott Wright said the 466 GW of nameplate capacity MISO envisions having in 20 years is going to be “a different animal” and introduce new market complexities. (See related story, MISO Modeling Line Options for 2nd LRTP Portfolio.)

“We’re going to have 400 GW, four times the load, because of the attributes we desire,” he told MISO’s Advisory Committee.

MISO said in the future it will likely measure hourly energy adequacy, use AI to manage uncertainty and target certain amounts of reliability attributes from generation.

“We feel we’re sitting in an untenable position not making these reforms, maybe sitting in an unsafe position not making these reforms,” Wright said.

WEC Energy Group’s Chris Plante said, “Maybe MISO should consider clearing an amount of resources with certain [reliability] attributes.” MISO has said six generating attributes are necessary to its system operations: availability, delivering long-duration energy at a high output, rapid startup times, providing voltage stability, ramp-up capability and fuel assurance. (See MISO to Evaluate System Attributes Through Year’s End.)

Plante said capacity auction prices bouncing from “next to nothing” to the cost of new entry is evidence that other states and load-serving entities might not be carefully planning how to furnish those attributes.

“We plan on bringing our fair share to the table. Others should do the same,” he said.

MISO Director Mark Johnson asked if some entities have possibly “lost sight of their obligation to serve” because they have belonged to the larger MISO resource pool for so long. Members pushed back and insisted their individual load obligations are top of mind amid the fleet transition.

McIntire said MISO’s Planning Resource Auction “isn’t necessarily giving us a signal about the future” because it measures capacity for only one year. She asked that MISO put together a “new, more formalized” resource adequacy forecast that predicts accredited capacity on five-, 10- and 15-year horizons.

MISO CEO John Bear said MISO has much to do to address emerging reliability risks. He said the ongoing discussion on how to encourage generation that can provide certain system attributes is crucial.

“How do we find these controllable, long-duration resources that can cover our risk during a wind or sun drought? We’ve got to work on that. We’ve got to get to that,” Bear said at MISO’s board meeting.

Posted on

BLM Seeks to Slash Fees for Solar, Wind on Public Land

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.

Posted on

House Energy and Commerce Examines Moore County Attack

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.

Posted on

Public Power Groups Seek Information on Mystic Agreement

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.

Posted on

Michigan Township Plans Floating Solar Farm

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.

Posted on

ISO-NE Outlines Economic Challenges of Decarbonization

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.
Posted on

Energy Bar Association Meeting Focuses on Financing Clean Power Transition

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.

Posted on

WECC Says Summer Looks Better with Caveats

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.

The assessment also noted the risk of wildfires to the transmission network, which can limit transfer capacity and lead to localized load shedding. (See NERC Warns of Summer Reliability Risks Across North America.)

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.