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November 1, 2024

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MISO, SPP to Conduct Interregional Study in 2024

MISO and SPP have agreed to conduct another coordinated system plan (CSP) study along their seam this year, as their joint operating agreement requires.  

Five previous studies have failed to produce a single interregional joint project over differences in how to allocate costs. The 2022 study focused on solutions that might qualify as targeted market efficiency projects (TMEPs), a construct MISO and PJM use on their seam. However, no projects met the criteria. (See MISO, SPP Fall Short in 5th Try for Interregional Projects.) 

The MISO-SPP joint operating agreement requires a CSP study at least every two years. 

During an Interregional Planning Stakeholder Advisory Committee meeting Feb. 22, several stakeholders offered suggestions on improving the CSP study process. 

“Even if problems are identified, cost allocation ends up disrupting the ability to actually progress to building projects that might address these issues,” Xcel Energy’s Madeleine Balchan said during the conference call. 

Xcel recommended that instead of looking at two different models and then trying to reach agreement with different sets of numbers, the grid operators look at the historical cost to the market of binding transmission lines along the seam. 

“Everybody can agree on the financial costs that have already happened,” Balchan said. 

“I never really could understand why we don’t hold up historical examples and try to figure out a way to learn from them,” North Dakota Public Service Commission analyst Adam Renfandt said. 

Natalie McIntire, representing the Sustainable FERC Project and Natural Resources Defense Council, urged the RTOs to use a more proactive, comprehensive interregional planning process with an agreed-upon single model and common benefit metrics. She called for employing scenario-based planning that addresses “credible ranges” of uncertain future conditions and a 15- to 20-year planning horizon, given the time it takes to develop multistate transmission. 

Missouri Public Service Commission economist Adam McKinnie drew support for his recommended focus in and around Southwest Missouri, home to numerous congestion issues. He suggested a three-way study among SPP, MISO and Associated Electric Cooperative Inc. The cooperative participates in the Southeastern Regional Transmission Planning process but conducts joint planning with SPP. 

“It seems like it would be beneficial if there was some way that we could get all three of those parties to study that area,” American Electric Power’s Jim Jacoby said. “It has had some severe problems that we’ve seen in past winter storms.” 

Ashleigh Moore, with MISO’s planning coordination and strategy team, said the two RTOs’ staffs will use the feedback to determine the CSP’s scope. Future IPSAC meetings will be scheduled to talk through the process. 

Separately, SPP on Feb. 22 filed a new revision request (RR620) to implement cost-allocation policies already approved by the RTO’s Regional State Committee for the Joint Targeted Interconnection Queue (JTIQ) project with MISO. The rule change would memorialize and define how the JTIQ would be deployed and applied once executed and is coordinated with changes to the JOA. 

SPP’s Clint Savoy said once RR620 is filed at FERC, staff will be able to work with MISO on TMEPs projects. 

Comments on RR620 are due by the close of business March 14. 

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Insurer: Majority of BESS Failures are in First Two Years

An insurer specializing in renewable energy infrastructure reports that battery energy storage system (BESS) failures are ramping up with the spread of the technology, and most often occur in new systems. 

It calls for developers and operators to take steps including creating spacing standards for units within a BESS, conducting comprehensive root cause analyses of failures, establishing a liability framework within the market and involving manufacturers through the entire project lifecycle. 

GCube issued the report, “Batteries Not Excluded: Getting the Insurance Market on Board with BESS,” on Feb. 21. CEO Fraser McLachlan said insurers experience uncertainties in supporting coverage for the rapidly expanding market.  

“GCube is a pioneer in the BESS field, and has learnt the hard way, having handled some of the largest losses in the market to date,” he said in the announcement of the report, which is designed to reduce market uncertainty. 

The report draws on details of 63 publicly reported failures. Among the findings: 

    • Systems rated at 5 to 50 MWh accounted for more than half of the failures and those rated at less than 5 MWh accounted for about a third. 
    • Solar-plus-storage installations accounted for 48% of reported failures; while this may be due to the frequency of such pairings, it also may point out challenges and risks created by pairing two complex systems. 
    • Nearly half the reported failures were in South Korea and nearly a third in the United States; this is likely due to the large number of systems in the two countries and the diligent reporting in both. 
    • Systems in their first year of operation accounted for 38% of recorded failures and 21% occurred within the second year. 

This last statistic is a red flag — GCube notes that the BESS failure rate within the initial operation phase is markedly higher than seen in other energy systems. 

“The high incidence of failures within the first two years of operation poses a serious cause for concern, warranting a closer examination of the potential ramifications if this trend continues,” the report warns. 

A report issued earlier in February flagged the same phenomenon from a different perspective: Engineering services firm Clean Energy Associates noted that 18% of its BESS factory quality control audits found issues with thermal management systems and 26% found faults with their fire detection and suppression systems. (See Engineering Firm Finds Quality Problems in BESS Manufacturing.) 

GCube said the risk as BESS systems get progressively larger is that failures will cause progressively larger damage, increasing the losses incurred by developers, operators and insurers. 

The 2012 fire at the First Wind/Xtreme Power wind-storage facility in Hawaii underwritten by GCube resulted in a $27 million loss, and that was only a 15-MW battery bank — a small fraction of the capacity of some of the BESS installations being planned and built. 

“We don’t want to repeat the mistakes of the past of allowing growth in deployment and technological scale to take priority over quality control, and the large-scale losses and market destabilization that result from that,” McLachlan said. 

Energy storage is a linchpin of the clean energy transition, and its rapid buildout reflects this. Batteries vastly outnumber other forms of storage. GCube expects that by the end of this year, BESS will account for as much as 30% of the asset value in its insured portfolio, which now exceeds 100 GW capacity. 

“Among the main challenges of BESS underwriting is the scarcity of data and insights on how BESS works, performs and fails,” McLachlan writes in the introduction to “Batteries Not Excluded.” 

“Consequently, underwriters continue to exercise caution when it comes to BESS technologies. While market data is limited, we must begin harnessing what information is presently available to start unravelling the risks and prospects associated with this nascent technology.” 

Beyond the financial and physical dangers of BESS failures, the sense of unknown danger stokes public opposition to installation of these facilities. (See Battery Storage Developers Bump Against Perception of Risk.)  

Jurisdictions such as New York state are moving to address the threat to public safety and perception by quantifying and reducing those risks as much as possible. (See NY Fire Code Updates Recommended for BESS Facilities.) 

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Entergy Highlights Data Center and Industrial Load Growth in Q4 Earnings

Executives focused on Entergy’s booming industrial load growth during a year-end earnings call Feb. 22.  

Entergy CEO Drew Marsh said that Entergy companies signed 61 new electric service agreements in 2023, representing 1.3 GW in capacity. 

“Data centers are a hot topic and, as you know, we’ve seen interest in our service area,” Marsh said, noting Amazon’s $10 billion arrival in Mississippi and Gov. Tate Reeves’ (R) signing bills in late January to authorize the data center investment along with $44 million in state incentives.  

Entergy has framed the Amazon Web Services data centers as a win for the state and touted its role in recruiting the company to the location. 

Marsh predicted “very strong growth” among Entergy companies going forward, due in part to new natural gas, blue hydrogen and EV battery production projects. 

“In addition to the data centers, our growth story continues to develop and diversity,” Marsh said, adding that Entergy has a “unique industrial growth opportunity in front of us.”  

Entergy’s load growth has been responsible in part for an unprecedented number of expedited project requests to MISO for transmission facilities. (See MISO to Re-examine Schedule for Reviewing Expedited Tx Projects.) 

Marsh said Entergy companies are pursuing loans and grants from the U.S. Department of Energy to offset the costs of much-needed grid upgrades. He said Entergy companies have applied for loans totaling $4.7 billion “for a variety of projects related to the clean energy transition” and have submitted eight preliminary proposals under DOE’s Grid Resilience and Innovation Partnership program. 

Entergy plans to invest $20 billion over the next three years to “make our fleet cleaner, to make our system more reliable and resilient,” Marsh said. That amount includes $11 billion in transmission construction, including big-ticket projects from MISO’s 2023 Transmission Expansion Plan. (See MTEP 23 Catapults to $9.4B; MISO Replaces South Reliability Projects.) It also includes $8 billion in new generation, including the more-than-$1 billion, 1.2-GW Orange County Power Station in southeast Texas and $2 billion for solar installations. 

Marsh said despite record-breaking heat last summer, Entergy achieved its lowest forced outage rate since 2011. 

“Not only did we meet our customers’ demands, but we also exported power to other utilities in MISO in the moments that mattered,” Marsh said. 

Marsh said Entergy’s year-end earnings of $1.4 billion ($6.77/share) signified “steady, predictable results.” Earnings over 2023 were slightly higher than 2022’s $1.3 billion ($6.42/share).  

Entergy CFO Kimberly Fontan said, “weather was a benefit for the year,” with an exceptionally hot summer boosting financial performance. 

Fontan said 2023’s retail sales volume was relatively flat overall, with industrial growth offset by a decline in residential and commercial demand. 

However, she said, industrial sales were not as “robust” as Entergy anticipated in the fourth quarter, although the utility remains optimistic about growth propelled by large industrial customers specializing in metals, gases and petrochemicals.  

“We continue to be confident in our industrial growth expectations, as sector margins and commodity spreads remain strong. And we continue to grow our backlog of signed electric service agreements,” she said.  

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SCE Sees Wildfire Risk Decline as Load Outlook Improves

Independent measures show Southern California Edison has sharply reduced its financial risk from catastrophic wildfires compared with pre-2018 levels, Pedro Pizarro, CEO of SCE parent Edison International, said during a Feb. 22 earnings call. 

The utility exceeded its own targets for hardening its system against fire risk last year when it installed 1,100 circuit miles of covered conductor across its distribution system, raising the total to 5,850 miles installed over the past five years.  

“We are proud of this progress, which, combined with enhanced vegetation management, asset inspections and other programs, has significantly reduced the need for public safety power shutoffs,” Pizarro said, referring to the fact that the physical measures have meant power shutoffs now account for just 10% of SCE’s fire avoidance, compared with 100% five years ago. 

On the heels of those developments, SCE last year showed an 85 to 88% reduction in its wildfire-related risks compared with pre-2018 levels based on an independent risk model managed by Moody’s RMS, he said. 

The utility in 2023 saw no fire ignitions due to the failure of covered conductor. Last year also marked the fifth straight year with no catastrophic wildfires in its service territory, according to a presentation shown during the call. 

The presentation also noted that SCE expects to have hardened 90% of its distribution lines in high-fire-threat areas (HFRAs) by the end of 2025, prompting one analyst on the call to ask whether the company is preparing to address new areas that emerge as high-risk in the future due to changing climate conditions. 

“Clearly, we continue to monitor how the landscape is changing,” Pizarro said. “We do that in partnership with fire agencies, with [California Office of Energy Infrastructure Safety], so to the extent that additional areas are designated HFRA, high-fire-risk areas, in the future, then we would make sure that we’re using the same standards that we use for high-fire-risk areas today.” 

Electrification to Boost Load, Reduce Energy Costs

Edison expects a significant boost from California’s push to decarbonize its economy, an outlook shared by its neighbor to the north, Pacific Gas and Electric. (See PG&E Foresees Strong Growth from Electrification, Data Centers.) 

“After years of flat demand, SCE is projecting an uptick in electricity usage of about 2% annually over the coming years,” Pizarro said, in line with PG&E’s forecast load growth of 1 to 3% through 2028. 

“As more and more vehicles and buildings are electrified, the electricity demand will increase by 80% over the next 20 years, which will benefit customer affordability through a 40% decrease in their total energy costs across electricity, gasoline, and natural gas,” he said. 

Pizarro said the expansion of high-voltage transmission and local distribution networks will be “critical” to California meeting its climate goals. Edison estimates a 6 to 8% compound annual growth rate in its rate base over the next five years, from $43 billion this year to $55.2 billion in 2028. That growth will be “driven by wildfire mitigation and important grid work to support California’s leading role in clean energy transition,” the company said in its presentation. 

The company also foresees the opportunity to expand its rate base by an additional $2 billion through investments in a “next-generation” enterprise resource planning system, advanced metering infrastructure, and grid reliability and resilience upgrades, as well as another $2 billion in transmission projects subject to FERC approval. 

In January, the California Public Utilities Commission rejected SCE’s 2021 proposal to spend $744 million to install new heat pumps in 250,000 homes in its territory and assist lower-income households with necessary electrical upgrades. The regulator expressed concern about spreading the costs for the program across the utility’s customer base at a time of already high energy costs.   

“A substantial amount of federal, state and ratepayer money is already being spent, and has been allocated for future use, to largely implement the same building electrification efforts in SCE’s proposal,” the commission said in its decision (A2112009). 

“Although the CPUC denied SCE’s building electrification application due to their near-term affordability pressures, it acknowledged SCE’s leadership in proposing programs to accelerate much-needed building decarbonization,” Pizarro said. “The utility will continue to evaluate the results of other building electrification pilots it has in progress and look for different ways to support the state in advancing its clean energy priorities.” 

Edison reported 2023 profits of $1.197 billion ($3.12/share), compared with $612 million ($1.61/share) in 2022. Fourth-quarter earnings came in at $378 million ($0.99/share), compared with $415 million ($1.09/share) a year earlier. 

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PG&E Foresees Strong Growth from Electrification, Data Centers

California’s “leadership in electrification” will be a key driver of Pacific Gas and Electric’s expected customer growth in the coming years, CEO Patti Poppe said Feb. 22 during the utility’s fourth-quarter and year-end earnings call. 

PG&E is forecasting annual load growth of 1 to 3% through 2028, based in large part on expectations for increased electrification and continuing uptake of electric vehicles among its customers, according to slides accompanying the call. 

The utility also foresees strong growth in demand from commercial customers, with service applications from new data centers increasing threefold last year over the previous four years. 

“As we look at the five-year forward load-growth forecasts, the back end of that forecast will reflect the additional data center demand,” Poppe said. “And look, I think we all can agree that the only thing that’s happening with data centers is they need more of them.” 

PG&E estimates $62 billion in capital expenditures over 2024-2028, with the spending supporting “strategic capital investments in electrification, energization, undergrounding and wildfire mitigation,” according to a footnote in the slides. That represents a 20% increase over the utility’s outlook for the 2023-2027 period and translates into a 9.5% compound annual growth rate (CAGR) for its rate base. 

The company also foresees opportunities for an additional $5 billion in spending over the next five years on transportation electrification infrastructure, transmission upgrades, incremental business connections, hydroelectric facilities and storage, and information technology and automation. 

Despite the anticipated sharp growth in spending, Poppe said the company expects to hold customer rate increases to 2 to 4% annually based on new cost-saving measures and the ability to spread costs over the growing load base. 

Poppe attributed the cost-saving to the utility’s adoption of a “lean operating system,” which last year drove a 5.5% reduction in nonfuel operations and maintenance costs after a 10% CAGR in those expenses during the previous five years. 

“As a reminder, several years of doing whatever was necessary to respond to back-to-back crises pushed our capital-to-expense ratio far below the industry average,” she said. “This is where we have a wealth of opportunity and a long runway to drive efficiencies with sustainable savings benefiting both our customers and our investors.” 

Poppe also touted PG&E’s improving record related to wildfire ignitions. 

The utility has been found responsible for its equipment sparking some of the most destructive fires in California’s history, including the deadly 2018 Camp Fire, which burned down most of the rural town of Paradise and killed 85 people. (See Cal Fire Pins Deadly Camp Fire on PGE.) 

PG&E started no “catastrophic” fires in its service territory last year, while tallying 68 reportable ignitions, compared with 91 in 2022, 134 in 2021 and 201 in 2017. Based on the scoring methodology established by the California Public Utilities Commission, the utility’s wildfire risk fell by 94%. 

“While we’re extremely pleased with these results, our team certainly isn’t stopping here. We see further opportunities to drive overall wildfire risk reduction beyond the 94% achieved in 2023 as we continue with additional system hardening and deployment of new technologies,” Poppe said. 

PG&E last year undergrounded 364 miles of distribution lines at a cost of just under $3 million per mile, bettering targets of 350 miles at $3.3 million per mile. Poppe said the work will help prevent public safety power shutoffs and other outages for 15,000 customers in areas of high fire risk. 

The utility expects to underground around 250 miles of lines this year, part of a plan to bury 10,000 miles of lines — or about 8% of its distribution system, Poppe noted. 

Pacific Generation a ‘Great Transaction’

PG&E is still awaiting the CPUC’s decision on the proposed spinoff and sale of a minority stake in Pacific Generation, a standalone subsidiary that would control 5.6 GW of generating capacity, including more than 1.3 GW of battery and pumped storage. FERC last year approved the plan, which would raise an estimated $3.4 billion for PG&E. (See FERC Approves PG&E’s Proposal to Spin off Generation.) 

“We think this a great transaction for customers,” PG&E CFO Carolyn Burke said, adding that the advantageous financing costs stemming from the spinoff will also improve the utility’s balance sheet and lower overall costs for utility customers. 

Both Burke and Poppe emphasized during the call that PG&E would not be seeking to raise money from equity markets this year because the company’s current stock price makes other financing options more “favorable.” 

PG&E reported earnings sat at the top end of previous estimates. The company made $2.242 billion last year ($1.05/share), compared with $1.8 billion ($0.85/share) in 2022. Fourth-quarter earnings per share jumped to 84 cents from 24 cents a year earlier. 

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Dominion Sells 50% of Coastal Virginia Offshore Wind to Stonepeak

Dominion Energy on Feb. 22 reported earnings of $2 billion in 2023 and announced that it has closed on an equity partner for its Coastal Virginia Offshore Wind (CVOW) project. 

The utility is selling a 50% noncontrolling interest in CVOW to Stonepeak through the formation of a new public utility subsidiary, under Virginia’s jurisdiction, that will own the project, while Dominion will continue to construct and eventually operate the wind farm on its own. 

“The Coastal Virginia Offshore Wind project continues to proceed on time and on budget and consistent with our previously communicated timing and cost expectations,” CEO Robert Blue said. “A competitive partnership process attracted high-quality interest, resulting in a compelling partner for CVOW. Stonepeak is one of the world’s largest infrastructure investors, with more than $61 billion in assets under management and an extensive track record of investment in large and complex energy infrastructure projects, including offshore wind. Their significant financial participation will benefit both our project and our customers.” 

The deal includes a number of provisions in which Stonepeak would share in any cost overruns, but Blue told investors on a conference call that he expects Dominion will complete CVOW on time and on budget. 

“We’ve been very clear with our team, and with our suppliers and partners, that delivery of an on-budget project is the expectation,” Blue said. 

Dominion posted a video highlighting the work it and suppliers have done on the project so far, with some monopiles being delivered to Virginia while construction continues on other components elsewhere, he added. 

The company has already invested $3 billion in the project, and it plans to put in another $3 billion before the end of the year. A little more than 92% of the project’s costs are now fixed, and the firm expects its final cost will be $9.8 billion. 

Stonepeak will pay Dominion about $2.9 billion once the deal closes to cover its pro rata share of investments so far, but the deal will have it invest about $4.9 billion assuming the cost is on budget. The investment firm could be on the hook for more, but its pro rata share of costs goes down the more costs overrun Dominion’s estimates, while the utility would wind up with a greater share of CVOW if costs are higher than expected. 

The deal has to get approval from the Virginia State Corporation Commission (SCC) and the North Carolina Utilities Commission. 

“It will be a public utility in Virginia and be entitled to recover its prudently incurred costs of constructing and operating the project under the existing offshore wind rider in Virginia,” Blue said. 

While last year Dominion was focused on getting a bill through the legislature that changed how Virginia regulates its business, this legislative session has been slow when it comes to electric power issues, Blue said. One exception was the legislature finally naming two new members to the SCC, which had been short staffed for years. (See Virginia State Corporation Commission Finally Gets All Seats Filled.) 

“They have extensive experience in both government and the private sector,” Blue said. “And we look forward to working cooperatively with these well qualified new members.” 

Dominion is going to be back before its investors shortly, with an investors day scheduled for March 1, at which it will present a “comprehensive strategic and financial update” and conclude the business review it has been working on for months. 

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Avangrid Avoids Major Offshore Wind Losses

Avangrid reported a year-over-year decrease in income but said a timely pause in its offshore wind projects saved it from write-offs that could have run into the billions. 

CEO Pedro Azagra gave an upbeat fourth-quarter and year-end assessment to financial analysts Feb. 22, noting significant progress on the long-delayed New England Clean Energy Connect transmission line and landmark achievements with Vineyard Wind 1, both now under construction. 

In 2022, Avangrid was one of the first developers to publicly sound the alarm about the financial crisis facing the nascent U.S. offshore wind industry, as projects that had locked in power purchase agreements years earlier saw their projected costs of construction soar.  

Developers holding contracts for more than half the contracted U.S. offshore wind capacity have canceled the contracts or the projects. 

In 2023, Avangrid agreed to $64 million in penalties to cancel its power purchase agreements for Park City Wind in Connecticut and Commonwealth Wind in Massachusetts. After taxes, the net cost was just $29 million, Azagra said.  

(See Park City Wind to Cancel PPAs, Exit OSW Pipeline and Commonwealth Wind PPA Cancellations OK’d.) 

By contrast, some other companies developing projects off the Northeast coast — BP, Equinor, Eversource and Ørsted — recently have reported huge impairments. 

“This allows us to maintain future profitable opportunities with this business,” Azagra said, “as opposed to our peers’ multibillion-dollar write-offs, which continue to mount.” 

Vineyard Wind 1, the nation’s first large-scale offshore wind project, was far enough along when supply chain constraints and cost increases hit the industry that it could continue to construction. (South Fork Wind, about one-sixth the size of Vineyard, also started construction around the same time and is nearing completion.) 

Avangrid and the state of Massachusetts chose Feb. 22 to celebrate the fact that five of Vineyard’s turbines are spinning at full capacity, delivering up to 68 MW of emissions-free electricity to Massachusetts. Five more are in place but not operational. 

That leaves 52 turbines and 738 MW to go, more than one year after construction started on Vineyard and nearly three years after federal regulators greenlighted the project.  

Azagra sidestepped an analyst’s question on when the 50-50 joint venture with Copenhagen Infrastructure Partners would reach full operation. 

“What we have learned in the last 12 months is a focus sometimes on specific deadlines is almost irrelevant,” he said. “The important thing is to finish the project.” 

In other news, Avangrid Networks President Catherine Stempien said construction of New England Clean Energy Connect in Maine is going well after litigation delays. (See New England Clean Energy Connect Wins Court Battle.) 

“Twenty-five percent of our foundations have been set and 20% of poles,” she said. “We’ve already started stringing conductor on the corridor. We’ve also been doing substantial construction laying the foundation for our HVDC converter station.” 

The line will bring 1,200 MW of power from Québec hydroelectric facilities to New England. 

Avangrid also continues selective onshore renewable development, Azagra said. It commissioned 311 MW of onshore capacity in 2023 and is working on projects totaling 998 MW, 687 MW of which is contracted to power data centers. 

Avangrid reported GAAP net income of $397 million for the fourth quarter of 2023 and $786 million for the full year. That compares with $147 million and $881 million, respectively, in 2022. 

GAAP earnings per share were $1.03 in the fourth quarter of 2023 and $2.03 for the full year, compared with $0.38 and $2.28, respectively, in 2022. 

Avangrid’s stock closed 0.3% lower Thursday amid average trading volume. 

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MISO Publishes Call to Action to Bypass Danger in Reliability Imperative Report

MISO has released a new edition of its Reliability Imperative report, with the latest version containing an urgent call to action for all MISO players.

“We have to face some hard realities,” MISO CEO John Bear prefaced the refreshed report. “There are immediate and serious challenges to the reliability of our region’s electric grid, and the entire industry — utilities, states and MISO — must work together and move faster to address them.”

The report emphasized that all three must coordinate at once to avoid a “looming mismatch” between retiring baseload generation and an influx of weather-dependent generation. MISO said members should temper retirements to retain some dispatchable “transition resources” as “reliability insurance.” 

MISO first published its Reliability Imperative report in 2020 and has updated it periodically since. It describes the RTO’s risk profile and the steps MISO, members and state regulators should take to mitigate threats. 

In a Feb. 21 press release accompanying the report, MISO said that in addition to “significant changes to the generation fleet, the electric power industry is facing an increase in extreme weather events, large load additions, electrification, supply chain issues, permitting delays and fuel assurance issues.”

Members have cut carbon emissions by about 30% since 2005, and Bear said the footprint could cut them by more than 90% in coming years. 

“Studies conducted by MISO and other entities indicate it is possible to reliably operate an electric system that has far fewer conventional power plants and far more zero-carbon resources than we have today. However, the transition that is underway to get to a decarbonized end state is posing material, adverse challenges to electric reliability,” Bear warned. He said that until new technologies become viable, MISO will continue to need dispatchable resources.  

“We’re seeing traditional generators being replaced by resources that aim to meet clean energy goals but that do not have the same reliability attributes as those they are replacing,” Bear said.  

MISO said supply chain and siting and permitting issues outside of MISO’s control are hampering new generation projects that will be crucial to reliability. The grid operator also said the footprint is increasingly housing single-site, large load additions like data centers that planned and existing generation might not be able to accommodate, especially when considering new pressure on the grid from electric vehicles and other electrification. 

MISO reported that its South region is experiencing an industrial renaissance and soon could add manufacturing plants producing steel, hydrogen, liquefied natural gas and other heavy industry totaling 1 GW in new demand. 

MISO said diminishing generation and load growth over the past decade-plus already have depleted its surplus reserves.

“Since 2022, MISO has been operating near the level of minimum reserve margin requirements,” it said. 

The RTO said ongoing initiatives into 2024 like applying a sloped demand curve in capacity auctions, introducing a capacity accreditation that’s more reflective of actual generator availability and planning a second long-range transmission portfolio should help the footprint make progress toward a more reliable transition.  

MISO President Clair Moeller said MISO sees “very little risk of overbuilding the transmission system; the real risk is in a scenario where we have underbuilt the system.” 

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FERC Catches Ketchup Caddy Co. in Another Fake DR Scheme in MISO

FERC is poised to levy $27 million in penalties on a Texas-based LLC meant to sell in-car ketchup holders that collected more than $1 million in undeserved MISO demand response payments.  

The commission issued a show-cause order Feb. 21 to Ketchup Caddy LLC and CEO and owner Philip Mango, indicating it will assess $25 million in civil penalties on Ketchup Caddy, $1.5 million in civil penalties on Mango and order Mango to disgorge $506,502, plus interest, in unjust profits for bogus load reductions unless he can offer an explanation (IN23-14).  

Philip Mango | Jen Mango

FERC’s Office of Enforcement concluded that Ketchup Caddy is a “fraudulent enterprise with no legitimate market activity, registering and clearing demand response resources without their knowledge or consent and collecting capacity payments in turn, without making payments to the registered resources.” Enforcement staff said Mango “made no attempt to contract with — or even to contact — legitimate customers, and the purported customers Ketchup Caddy registered with MISO would not have responded if dispatched.”  

According to enforcement staff, Ketchup Caddy, Mango and co-founder Todd Meinershagen collected more than $1 million in fraudulent capacity payments beginning with the 2019/20 MISO capacity auction. In doing so, the company denied other MISO suppliers the opportunity to earn more than $17.6 million because its fraudulent offers suppressed capacity prices in the 2019/20, 2020/21 and 2021/22 MISO Planning Resource Auctions. The company received weekly capacity payments until October 2021, when MISO became aware of the scheme and removed Ketchup Caddy from its capacity market.  

Mango admitted to having no intention of enrolling actual customers, FERC staff said, and neither he nor Meinershagen attempted to defend their actions.  

Meinershagen already agreed to pay more than $525,000, including interest, for his role in the market manipulation as part of a December 2022 settlement agreement.  

Meinershagen, a computer programmer, reportedly used a random number generator on an Ameren website to land on actual customer accounts and “scrape” customer data. Staff said it was Mango’s responsibility to contact customers and convince them to participate in a demand response program with zero payout to them and 100% going to Ketchup Caddy. Mango said he never contacted potential demand response customers and never attempted to draft contracts because there was no way customers were going to agree to accept nothing. By early 2019, he had run out of time and fraudulently registered unwitting customers.  

“We were accepted in late February and had 48 hours to load customers into the MISO program before it closed,” Mango said of his experience registering demand response with MISO.  

FERC staff said Ketchup Caddy cleared 211.1 MW in the 2019/20 MISO capacity auction, 303.2 MW in the 2020/21 auction and 372.3 MW in the 2021/22 auction. The commission said Ketchup Caddy’s false registrations and offers went under the radar because MISO didn’t order curtailment in any of those planning years and only required “mock tests to verify performance.”  

Mango said he was looking for “essentially free money, no harm to the customer” and told staff that he planned to“[d]o this for just a couple of years, make a bunch of money to put kids through school and do all those things, and no one’s hurt. Do it with the least amount of resource possible, the least amount of money invested.” 

Mango reportedly admitted that his company didn’t provide any value to the MISO market and any “reasonable person” would conclude that his actions were illegal. Mango also said he kept Meinershagen in the dark” and created a “mirage” to make him believe that Ketchup Caddy was legitimate.  

“Upon further reflection, I realize the egregiousness and the error of my ways,” he told FERC staff.  

Ketchup Caddy’s LinkedIn page routes to a distributor page for Plexus, a multilevel marketing company that deals in dietary supplements. MISO recognized Ketchup Caddy as a market participant in late 2018. The Frisco, Texas-based company was originally created by Mango to sell an in-car ketchup holder he invented.  

FERC gave Mango 30 days to respond to its order. Mango can choose between a prompt penalty assessment, or he can plead his case at an administrative hearing before an administrative law judge.  

This is the third time companies have been caught manipulating MISO’s demand response program and collecting unjustified payments, with penalties set to reach several million dollars.  

In January, FERC’s Office of Enforcement found that an air separation facility in Indiana accepted payments for phantom load reductions. It ordered Northern Indiana Public Service Co. and the U.S. arm of U.K.-based chemical company Linde Inc. to pay $66.7 million to settle charges it gamed MISO’s demand response program. In that case, FERC found that Linde’s Calumet Area Pipeline Operations Center in northwest Indiana would operate some equipment in the facility needlessly and vent gases it distilled back into the atmosphere, solely for the purposes of raising its registered baseline electricity use with MISO. (See FERC Orders $66.7M in Penalties and Disgorgement on Linde and NIPSCO.)  

Last year, FERC ordered an Arkansas steel mill and Entergy Arkansas to return a $35 million settlement for the steel mill’s yearslong failure to reduce electricity use as a demand response resource. Soon after, MISO’s Independent Market Monitor recommended the RTO implement demand response offer floors and attestations of expected levels of energy consumption to ward off similar DR schemes in the future. (See IMM Presses MISO for New Rules After DR Market Gaming.)  

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Prices, Renewables Rise in New England Capacity Auction

[Editor’s Note: This story was updated to correct some details of the capacity awards.]

ISO-NE’s capacity market continued its rollercoaster ride as prices for Forward Capacity Auction 18 rose to $3.58/kW-month, a nearly $1 increase (38%) over last year and the second highest “Rest-of-Pool” price since FCA 13. 

The RTO, which completed the auction after four rounds of bidding on Feb. 5, filed its results for FERC approval Feb. 21 (ER24-1290). The RTO asked FERC to set a deadline of April 8 for comments.  

The auction for the June 1, 2027-May 31, 2028, delivery year procured 31,556 MW of capacity — slightly above the 30,550-MW net installed capacity requirement (ICR) — from about 950 resource obligations, ranging from 7 kW (Sunnybrook Hydro 2) to the Seabrook and Millstone Point Unit 3 nuclear plants at 1.2 GW each. The capacity will cost ratepayers about $1.3 billion. 

Last year, prices cleared at $2.59/kW-month in all zones and import interfaces except for the New Brunswick interface, which cleared at $2.551. (See FCA 17 Shows Clean Energy Boost, Endgame for Coal in New England.) 

ISO-NE’s calculation of the quantity of capacity procured is based on the amounts for June 2027. Among fuel types, natural gas led with 13,817 MW (44% of the total), followed by fuel oil and nuclear at 11% each, and hydropower at 10%.

Demand response contributed 2,614 MW (8%), followed by electricity used for energy storage (5.8%)

Solar (2.2%) and wind (1.7%) trailed kerosene at 3%, although their combined total of 3.9% was up from about 3% in last year’s auction.

Imports contributed 1.5%.

New resources represented 1,484 MW, 4.7% of the total, including 741 MW of storage, 185 MW of wind and almost 53 MW of solar.

In total, the RTO said, emissions-free renewable generation, storage and demand resources contributed about 40% of the total at almost 1,085 MW. 

ISO-NE capacity demand curve, net installed capacity requirement (net ICR) and net cost of new entry (net CONE) for Forward Capacity Auction 18 | ISO-NE

Zones

The auction set separate zones for Northern New England (New Hampshire, Vermont and Maine load zones), Maine (modeled as a nested export-constrained zone within NNE), and the Rest-of-Pool. 

The ROP included Southeastern Massachusetts, Rhode Island, Northeastern Massachusetts/Boston, Connecticut and Western/Central Massachusetts.  

The descending clock auction started in each zone at $14.525/kW-month, resulting in a clearing price of $3.58/kW-month for all zones and imports over the New York AC ties (122.89 MW), New Brunswick external interface (70 MW), Hydro-Québec Highgate external interface (18.17 MW) and the Phase I/II HQ Excess external interface (253.78 MW). 

There were no active demand bids for the substitution auction and the RTO did not reject any retirement delist bids for reliability reasons.