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November 8, 2024

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DOE Study Adds to Case for Interregional Offshore Grid

An interregional transmission network for the East Coast’s offshore wind could produce almost $1.6 billion annually in generation savings and improved reliability versus radial lines, according to a study released by the U.S. Department of Energy last week. 

The Atlantic Offshore Wind Transmission Study calculated substation and cable costs for a 2050 “low-carbon” scenario with 85 GW of offshore wind from Maine to South Carolina. The analysis considered four offshore transmission topologies against a reference case using radial lines for each project with no links between offshore platforms:  

    • an intraregional topology with connections within regions;  
    • an interregional topology connecting diverse regions;  
    • an inter-intra topology combining the links in the interregional and intraregional topologies; and  
    • a backbone grid that adding interregional plan an additional cable running from Maine to South Carolina. 

The analysis, by researchers from the National Renewable Energy Laboratory and the Pacific Northwest National Laboratory, found that each of the four networked topologies had higher benefits than costs and that the interregional plan produces the highest benefit-to-cost ratio and total net value. 

Networking offshore transmission would reduce offshore wind curtailments (1 to 2 percentage points below the radial topology) and the use of higher-cost generators, DOE said. It would also increase reliability by providing alternatives during outages of other transmission lines or generation, particularly during winter peak conditions.  

“In modeled estimates using the radial topology in 2050, price differences between suitable POIs for offshore wind averaged over $100/MWh,” the report said. “This price difference is higher than the average wholesale electricity prices in recent years in some Atlantic market regions. High price differences indicate that offshore transmission with interlinking platforms can consistently flow power from lower- to higher-price regions to benefit electricity consumers by reducing the costs of generating electricity.” 

Intraregional, interregional, and backbone transmission topologies | National Renewable Energy Laboratory

The researchers’ modeling of the networked transmission showed that flows on all interlinks go both directions every season, with an average utilization rate of 50 to 60% of the available capacity on each line.  An interregional grid with a 14,000-MW capacity could displace up to 4,700 MW of firm generation capacity, the researchers said. 

The base radial plan is estimated to cost $96.3 billion. The interregional grid would add $11.4 billion in capital costs, with annualized capital and operations and maintenance costs of $840 million. But DOE said it would produce benefits of $2.4 billion annually, a benefit-to-cost ratio of 2.9. 

The backbone topology provides the second-largest ratio of 2.7, with annualized costs of $1.47 billion and benefits of $3.9 billion per year.  

The analysis envisions building offshore transmission in phases to reduce development risk and assumes the first offshore wind projects would be connected to the grid with individual radial lines. But researchers said, “early implementation of high-voltage direct current (HVDC) technology standards is essential for future interoperability.” 

The only potential negative identified by researchers: Offshore wind could be vulnerable to extreme weather in the ocean and at landing points. 

DOE’s report adds to earlier research on the benefits of a planned Atlantic offshore grid, including a 2023 Brattle study that estimated coordinated transmission planning could produce at least $20 billion in transmission-related cost savings, 60 to 70% fewer shore crossings and a reduction of about 50% in marine transmission cables (2,000 fewer miles) on the seabed. (See OSW Transmission Planning Must be Interregional, Networked and Start Now.) 

Implementation Steps

DOE’s study was accompanied by an action plan from DOE’s Grid Deployment Office that identifies the steps researchers said would be required to implement the transmission buildout. It calls for establishing collaborative bodies spanning the Atlantic Coast this year to plan transmission and cost allocation during the second half of the decade. 

It encourages RTOs and other transmission providers to simultaneously evaluate multiple benefits beyond reliability or production cost savings.  

In its transmission planning and cost allocation rulemaking, which FERC is expected to finalize this year, the commission proposed developing long-term scenarios for use in regional planning, with an increased role for states in facility selection and cost allocation. FERC has also proposed a minimum set of benefit categories with methods to quantify them (RM21-17). (See FERC Watchers Weigh in as Transmission Rule Approaches Finish Line.) 

Among the “Immediate Actions Before 2025” in the action plan is voluntary cost-allocation assignments. “Transmission cost allocation is a notoriously thorny issue that is intensified by the scale of projects and large price tags associated with interconnecting offshore wind,” DOE said. “In fact, the Business Network for Offshore Wind [recently renamed the Oceantic Network] described the issue of who pays as ‘the hardest single problem for transmission.’” 

‘Most Thorough Analysis’ to Date

DOE called its two-year study the most thorough analysis to date of options to bring the East Coast’s wind energy — projected to be a key part of the region’s decarbonization — ashore. 

The study focused on the offshore region between Maine and South Carolina and the onshore grid in those states, plus Vermont and Pennsylvania due to their proximity to the Atlantic. The 85-GW scenario for 2050 projects 27 GW of OSW injection into ISO-NE; 19 GW into NYISO, 26 GW into PJM and North Carolina, and 13 GW into the SERC Reliability Corp. region in North Carolina and South Carolina. Offshore wind would represent more than 20% of generation in NYISO and PJM and more than 40% in ISO-NE. 

The report identifies potential transmission corridors considering environmental concerns and other uses such as military zones and shipping channels. The researchers cautioned that their analysis did not have the level of detail of interconnection studies and was not intended to prescribe exact injection points.

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WEIM Expert Calls for Fast-start Pricing to Address ‘Anomalies’

Fast-start pricing could fix certain “price anomalies” in CAISO markets more effectively than existing mechanisms for compensating ramping resources, the Western Energy Imbalance Market Governing Body’s market expert told the group.  

“The primary objective of fast-start pricing is to provide a more efficient price signal when fast-start units are dispatched to meet load,” Susan Pope, an electric power consultant appointed to assist the WEIM body, said during the group’s March 19 monthly meeting.  

“The more accurate fast-start pricing signal cannot always and will not always be provided by either the flexible ramping product or shortage pricing,” Pope said.  

Out of the six FERC-jurisdictional organized markets, CAISO alone doesn’t use fast-start pricing, a mechanism that factors the cost of starting and operating gas-fired peaking units into the wholesale market price.  

According to a June 2022 analysis published by Powerex and the Portland, Ore.-based Public Power Council (PPC), CAISO and its Department of Market Monitoring (DMM) have actively opposed fast-start pricing and instead chose to rely on out-of-market payments to individual units to enable them to break even on daily variable costs.  

But absent fast-start pricing, market prices may not reflect the cost of meeting incremental load when starting and operating natural gas units to meet peak demand, undermining the accuracy of pricing in the WEIM — and, paradoxically, causing participants to potentially pay more than necessary in some intervals.  

“The understated price could incorrectly encourage parties to schedule additional exports, even though the price for meeting the export schedule in the dispatch could turn out to be higher than the understated price they actually end up paying,” Pope said. “The flip side of this is that the price signal for incremental supply is also understated, which sends the wrong signal to encourage incremental supply to offer the dispatch.” 

Pope also pointed out the 2022 report may have substantially overstated the potential price impact of fast-start pricing due to a lack of nonpublic data CAISO since has gained access to.  

In December, CAISO presented its own analysis of fast-start pricing and sought stakeholder feedback for developing its scope. 

Flexible Ramping and Shortage Pricing

Other pricing mechanisms, such as the flexible ramping product and shortage pricing, won’t fix the fast-start pricing issue, Pope said, because while they can overlap and trigger simultaneously, they operate under different grid conditions and provide distinct functions.  

“The underlying reason why the flexible ramping product and shortage pricing will not fix the fast-start pricing anomaly is at root because the three pricing enhancements are aimed at fixing different things,” Pope said. For example, fast-start units could be dispatched to meet load when there is neither a flexible ramping constraint nor a capacity shortage, meaning that neither of the alternatives can be relied upon to substitute fast-start pricing.  

Impact on the WEIM

The use of fast-start resources to meet incremental load would increase locational marginal prices and potentially reduce emissions, Pope said. 

“One of the possible benefits of fast-start pricing is to enable others who are not required to bid or offer into the market to see the higher price and choose to participate, and by their participation, offer the opportunity to displace the start-up of more costly emitting units,” she said. The higher prices also could improve market efficiency by increasing the number of bids and offers, she added.  

The potential environmental impact of not using fast-start pricing was a key concern outlined in the 2022 analysis, which identified that lack of the price signal could weaken carbon-pricing programs.  

“The calculation of wholesale market prices in CAISO-operated markets not only excludes the cost of starting and operating natural gas peaking units, it also excludes the cost of GHG emissions from those units, which can be among the highest in the grid,” the report reads. “This undermines a key goal of carbon-pricing programs, including California’s cap-and-trade program as well as programs being explored by multiple other Western states.”  

Fast-start Pricing in Other Markets

Examining the efficiency of fast-start pricing in other RTOs and ISOs can offer CAISO insight into how the mechanism could operate in its markets, Pope said.  

Fast-start pricing has been a feature of NYISO since 1990 and MISO since 2010, and independent market monitors are divided on their views on the mechanism.  

According to Potomac Economics, the IMM for NYISO, MISO and ERCOT, fast-start pricing has “significantly improved real-time price formation in MISO” and “has led market price signals to better reflect system conditions and provide better performance incentives for flexible resources when fast-start units are deployed” in NYISO.  

PJM IMM Monitoring Analytics takes a dimmer view, finding that fast-start pricing distorts “the correct signal for efficient behavior” and inappropriately pays higher prices to inflexible generators.  

And in 2023, CAISO’s DMM said fast-start pricing “is inconsistent with the features of locational marginal pricing that maximize market surplus and provide incentives for units to operate at the most efficient, socially optimal dispatch level.”  

It’s unclear whether an existing fast-start pricing design could be added easily to the WEIM of the ISO’s Extended Day-Ahead Market. Even if the mechanism is effective in other regions, Pope said, market changes would be needed to reflect the scheduling and pricing modeling runs used for WEIM dispatch, which CAISO still is studying.  

Regardless of the challenges, WEIM Governing Body members appeared open to considering fast-start pricing.  

“It is a subject of great interest and much debate, and I think we could all use a greater understanding of this and how it applies in the current West,” said WEIM Governing Body member Robert Kondziolka.

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‘Evolution’ Key Theme at IPPNY 2024 Spring Conference

ALBANY, N.Y. — The Independent Power Producers of New York (IPPNY) celebrated its annual spring conference March 19 by marking the state’s transformation into a competitive energy market over the past 25 years with the inception of NYISO. 

Industry experts from the government, business sector and advocacy groups shared their insights on New York’s progress in evolving its energy markets, echoing sentiments from last year’s conference. (See Overheard at IPPNY 2023 Spring Conference.) 

FERC Chair Willie Phillips | © RTO Insider LLC

FERC Chair Willie Phillips discussed how the commission’s priorities have shifted toward improving “transmission to figure out how to better integrate new resources onto the grid,” enhancing the “grid’s physical and cybersecurity infrastructure,” and promoting environmental justice, which he considers a “top priority.” 

Suedeen Kelly, a partner at Jenner & Block and former FERC commissioner, concurred, saying that while the initial goals of establishing competitive markets centered around “efficiency, lowering costs and innovation,” they have shifted to include “decarbonization and the recognition of environmental and social justice” as the grid and energy markets have evolved and new generation technologies have emerged. 

Kelly praised New York’s market evolution, thanking participants for their efforts “to continue to meet the challenges of new technologies and incorporating those technologies into your market, since you’re taking huge risks to do this.” 

IPPNY President Gavin Donohue remarked in the same panel that the “competitive energy market has evolved into a bipartisan issue,” which will help to “lay the foundations for the future.” 

New York PSC Chair Rory Christian | © RTO Insider LLC

New York Public Service Commission Chair Rory Christian emphasized the theme of market evolution during his keynote address, highlighting how the commission’s decisions ensure that New York’s energy markets continue to adapt with the times. “Our daily lives depend on our ability to wield the magic of new technologies” he said, and “our actions can mean the difference between opportunity and calamity and can have ripple effects that extend far beyond our state borders.” 

“The commission has been able to lead and innovate,” he added, recognizing the need to develop a more holistic and adaptable approach that “ultimately culminated in a departure from vertically integrated utility models to a restructured wholesale energy market that incorporates competition.”

C. Lindsay Anderson, a professor of biological and environmental engineering at Cornell University, spoke about the growing recognition among New York energy stakeholders that to meet the state’s energy priorities and mandates and “to decarbonize everything, [we must] first decarbonize the power system.”

Panelists at the “Lobbying the Legislature and Executive Branch – Important Topics this Session” panel discussed how their clients and objectives have also evolved in response to New York’s policies. 

Elizabeth Garvey, an attorney at Greenberg Traurig, noted how she’s observed a shift in how political and corporate clients focus on broader engagement.  

“These years, unlike past years … [clients] really focus on all of [the market’s] issues wherever they sit in the energy economy … even if it doesn’t directly impact [them],” Garvey said. 

She added that the state’s evolving market and policies have led to an “inflection point” where it has become increasingly difficult to tell clients “where they should park their capital” since “there are so many different things happening on so many different playing fields” both in New York and across the nation. 

IPPNY

Will Hazelip, National Grid | © RTO Insider LLC

Will Hazelip, president of National Grid Ventures, US Northeast, said modernizing the transmission system is one of the biggest future challenges for New York and the country.  

“Redoing the transmission system will help enable power to move around” and also help clients “know for certain when they can build and then plug in,” he said. 

Phillips summarized the evolving perspective of conference panelists and the wider industry, saying, “As we celebrate the 25th anniversary of the [New York] market, the subtitle has been ‘cleaner, safer and cheaper,’” but “what I now say is ‘reliable, affordable and sustainable.’” 

“We need a new generation to think differently about our problems,” Phillis said, noting how energy markets, technologies and policies have evolved.  

The industry can no longer pretend “the benefits of our transition fall evenly on everyone,” he said. 

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Texas PUC Establishes $5B Energy Fund

The Texas Public Utility Commission on March 19 adopted a rule establishing the Texas Energy Fund In-ERCOT Generation Loan Program, a $5 billion fund designed to bring new dispatchable power projects to the state. 

The rule establishes the fund’s application process, project eligibility requirements, evaluation criteria and loan terms. The low-interest loans can be used for new dispatchable generation facilities or to expand existing facilities within ERCOT (55826). 

Qualifying projects for the Texas Energy Fund (TEF) must add at least 100 MW of new dispatchable capacity to the grid. The PUC says the program can support up to 10 GW of new or upgraded generation capacity in ERCOT. 

“As our state’s population and economy grow, so does the demand for electricity, and we must ensure Texans have the power they need, when they need it,” PUC Chair Thomas Gleeson said in a statement. “This rule lays a strong foundation for the Texas Energy Fund’s success and for future investment in the state.” 

Speaking on a panel during the recent CERAWeek 2024 by S&P Global conference in Houston, NextEra Energy’s Michele Wheeler, vice president of regulatory and political affairs, said the market indicates the fund will be oversubscribed. 

“We hope that’s the case,” she said. 

NRG Energy’s interim CEO, Larry Coben, said in February the company plans to apply for up to $900 million in TEF loans to finance construction of two new natural gas-fired plants that would be available in 2026. Coben reiterated during CERAWeek that the two peakers and another baseload plant will add 1,500 MW to the Texas grid. 

Companies can begin applying for the in-ERCOT program June 1. Initial disbursements for approved loans will be issued by Dec. 31, 2025. 

However, supply chain issues could pose a significant roadblock, commissioner Jimmy Glotfelty said during the March 21 open meeting. He recounted a conversation he had during CERAWeek with a Siemens senior executive. 

“He said, ‘Good luck with getting a combustion turbine before 2031,’” Glotfelty said. “If the market [is] seeing a massive delay in this major equipment, I think that is something that really has to be conveyed to the legislature and to us so that we don’t get in a bind.” 

One of the TEF’s four programs, an early completion bonus, awards grants to new dispatchable generation facilities that meet certain planning requirements after June 1, 2023, and interconnect to the ERCOT grid before June 1, 2029. 

The commission agreed with stakeholders to change the rule’s performance standards and ordered the revisions during the meeting. The performance availability factor (PAF) was reduced from 90% to 85% and the performance outage factor (POF) rose from 10% to 15%.  

Gleeson said in a memo he was persuaded by commenters who said the performance metrics would be “very difficult to achieve” throughout the loan’s term for units operating under standard operating processes. The commenters said that because of the length of planned maintenance outages and “unforeseen operational issues” during the early years of a plant’s life, additional flexibility in the PAF and POF metrics is “both necessary and reasonable,” Gleeson said. 

In addition to the In-ERCOT Generation Loan Program, the rule establishes TEF programs providing: 

    • completion bonus grants for new dispatchable generation projects that “consistently provide power generation over a 10-year period”;
    • grants for companies to establish or secure back-up power resources; and
    • grants to improve electric service resiliency and availability outside the ERCOT region. 

The Texas Legislature could provide additional TEF funding in future years, the PUC said.  

PUC staff determined switchable resources providing energy to both ERCOT and SPP are not eligible for the fund, as they are not totally committed to the Texas market. However, they will be eligible for completion bonuses because the law does not make a distinction between ERCOT and non-ERCOT resources. 

“We want 100% of the new capacity generated to be dedicated to the ERCOT market,” PUC staffer David Smeltzer said. 

The TEF is a result of legislation passed last year (Senate Bill 2627). Texas voters overwhelmingly approved the fund in November as a constitutional amendment. (See 2023 Elections Bring Billions for Texas Gas, Dem Wins in Virginia, NJ.) 

“Voters … made it clear that reliable electricity is a top priority,” the bill’s author, state Sen. Charles Schwertner (R), said. “We must expand and strengthen our on-demand, dispatchable power generation in order to deliver the reliable electricity all Texans expect and deserve.” 

ERCOT Preps for Solar Eclipse

ERCOT COO Woody Rickerson told the commission the grid operator is preparing for the April 8 total solar eclipse and does not expect reliability problems, using lessons learned from October’s annular eclipse. 

“ERCOT will pre-posture the system just like we did previously as necessary to meet both [solar’s] down ramp and the up ramp,” he said. 

The eclipse will cross Texas from the southwest to the northeast between 12:10 p.m. and 3:10 p.m. CDT, with sun coverage ranging from 81 to 99%, ERCOT said. Solar generation is projected to dip as low as about 7.6% of its maximum clear-sky output at about 1:40 p.m. 

“That’s a pretty big ramp down,” Rickerson said. “We are fortunate that this solar eclipse is occurring in April and not August.” 

ERCOT is working with solar forecast vendors to ensure models account for the eclipse’s effect. Ancillary services will be used for additional balancing needs. The first market notices will go out March 28, with additional communications to the market following. 

The ISO breezed through a test case in October. Solar production dropped from just over 7,000 MW to 1,474 MW as the eclipse’s “ring of fire” traversed Texas. Natural gas resources helped compensate for the solar drop, increasing generation by more than 4,000 MW increase. (See ERCOT Smoothly Handles Annular Solar Eclipse.) 

Texas A&M University’s Smart Grid Center has made public a visualization of the eclipse’s effect on solar generation across Texas. ERCOT has about 22 GW of installed solar capacity. 

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PJM Awaiting FERC Response to Court Rejection of 2024/25 Capacity Auction Parameters

VALLEY FORGE, Pa. — The future of the 2024/25 Base Residual Auction (BRA) results is uncertain following a ruling from the 3rd U.S. Circuit Court of Appeals partly vacating a FERC order authorizing PJM to change an auction parameter after bids had been received (ER23-729).  

The court’s March 12 ruling found the commission violated the filed rate doctrine in accepting a PJM proposal to revise the locational deliverability area (LDA) reliability requirement for the DPL South zone, which covers much of the Delmarva peninsula. 

PJM sought the change after identifying a nearly fivefold increase in capacity prices due to the interaction between a “misalignment” in resources that offered into the auction and the expected resource pool with the determination of the reliability requirement. (See 3rd Circuit Rejects PJM’s Post-auction Change as Retroactive Ratemaking.) 

Speaking during the March 20 meeting of the Markets and Reliability Committee, Senior Counsel Chen Lu said the RTO anticipates court approval for a new course of action about early May, following a 45-day deadline for FERC to propose a new directive for PJM and about seven days for the court to review. He added PJM is not planning to request a rehearing or appeal of the ruling to the Supreme Court. That option is open to FERC and intervenors in the case. 

PJM Vice President of Federal Government Policy Craig Glazer said if rehearing or an appeal is sought, that could delay PJM knowing how to proceed with the capacity results. He added that the courts don’t have hard timelines on which they must act, raising the possibility that uncertainty around capacity prices could extend into the delivery year, which starts in June. 

“If rehearing is sought, it kind of freeze-frames everything,” he said. 

Lu said PJM is assessing the feasibility of rerunning the auction with the original LDA reliability requirement parameter for DPL South with the existing offers submitted in December 2022.  

PJM Senior Vice President of Market Services Stu Bresler said the RTO is in contact with FERC staff to provide perspectives on possible next steps. But he told the MRC he could not speculate about what those steps might be. If the auction did have to be run, he said the impact would likely spread outside the DPL South zone. 

Paul Sotkiewicz, president of E-Cubed Policy Associates, encouraged PJM to remain in communication with FERC to encourage it to come to a resolution the court could accept as quickly as possible, noting that using the full 45 days it has to respond could put resolution of the dispute within a month of the start of the delivery year. 

“We’re right before the delivery year at this point; it’s really cutting this close, so I’m wondering if there’s a way to accelerate that time frame,” he said. 

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FERC Upholds, Clarifies Generator Interconnection Rule

FERC on March 21 rejected challenges to its new generator interconnection rules under Order 2023 while offering several clarifications, minor modifications and an extended compliance deadline. 

Issued in July, Order 2023 sought to clear backlogged interconnection queues by implementing a first-ready, first-served cluster study process; increasing interconnection customers’ financial obligations; and penalizing grid operators for missing study deadlines. (See FERC Updates Interconnection Queue Process with Order 2023.) 

The commission received 32 requests for rehearing or clarification of the order, which required changes to the pro forma large generator interconnection procedures (LGIP), pro forma large generator interconnection agreement (LGIA), pro forma small generator interconnection procedures (SGIP) and pro forma small generator interconnection agreement (SGIA). 

The rehearing requests were automatically denied when FERC failed to act on them within 30 days, but the commission addressed all the filings in the 1,063-page order issued at its monthly open meeting (Order 2023-A, RM22-14-001). 

Order 2023 is the subject of at least a dozen challenges filed in federal appellate courts since October. Challenging the order are PJM, SPP and NYISO; transmission owners in NYISO and MISO; utilities PacifiCorp, Avangrid, Exelon, Dominion Energy, Florida Power & Light and FirstEnergy; and Advanced Energy United. 

‘Not a Problem that Only Exists in Isolated Pockets’

The commission rejected complaints it exceeded its authority under the Federal Power Act and denied it had declared all existing interconnection tariffs — including recently approved revisions by PJM and Dominion Energy South Carolina — unjust and unreasonable. 

“The findings in Order No. 2023 relate to the commission’s existing pro forma generator interconnection procedures and agreements, which, among other things, relied on a serial first-come, first-served study process,” it wrote. “The commission did not make any findings regarding specific transmission provider’s tariffs, and it was not required to do so under FPA Section 206. Issues regarding the individual tariffs of specific transmission providers that currently deviate from the existing pro forma generator interconnection procedures and agreements will be addressed on an individual basis on compliance.” 

FERC said interconnection queue delays “are a nationwide problem, not a problem that only exists in isolated pockets,” noting that less than 25% of requested interconnection capacity reached commercial operation between 2000 and 2017 in every region, with some regions as low as 8%. 

“The commission carefully examined recent queue-reform proposals to identify best practices to implement nationwide. However, no transmission provider has yet adopted all of the reforms in Order No. 2023,” it said, adding that it “would be waiting a very long time indeed if it could not issue a generic rulemaking while any individual transmission provider pursues its own regional queue reform.” 

FERC also rejected PJM’s assertion that some transmission providers should be presumed to be in compliance with Order 2023: “While the majority of reforms adopted herein are based on individual and incremental improvements that one or more regions have already implemented, no transmission provider has yet to adopt the entirety of Order No. 2023’s broad suite of reforms,” it said. “Thus, we are unpersuaded by PJM’s arguments on rehearing that ongoing, recently approved interconnection queue reform packages presumably already comply with Order No. 2023. Applying a presumption to transmission providers who recently adopted some similar reforms, but not all the reforms contained herein, will only result in incomplete change that fails to fulfill or further delays the comprehensive reform required by Order No. 2023.” 

Changes

The revised order: 

    • specifies that interconnection customers in the queue of a transmission provider using or transitioning to a cluster study process must comply with the transmission provider’s new readiness requirements within 60 days of the effective date of the transmission provider’s compliance filing. The commission also added a new section, 5.1.2, to the pro forma LGIP, stating that transmission providers that have adopted a cluster study process or begun a transition to it will not be required to implement the transition process specified in Order 2023. 
    • specifies that a network upgrade required for multiple interconnection customers in a cluster may be considered a standalone upgrade if the customers agree to build. It agreed with Advanced Energy United, the American Clean Power Association and the Solar Energy Industries Association that it should revise the definition of standalone network upgrades to maintain the pre-Order 2023 opportunity for interconnection customers to exercise the option to build as part of the cluster study process. 
    • requires transmission providers to complete their determination that an interconnection request is valid by the close of the cluster request window so that only interconnection customers with valid interconnection requests proceed to the customer engagement window. It set aside paragraph 234 of Order 2023 to clarify that an interconnection customer’s cure period ends at the close of the cluster request window at the latest. 
    • expands the acceptable forms of security for the commercial readiness and study deposits to include not only cash or an irrevocable letter of credit, but also surety bonds or other forms of financial security that are “reasonably acceptable to the transmission provider.” 

The order also provided clarifications on the allocation of cluster network upgrade costs; withdrawal penalties; study delay penalties; availability of surplus interconnection service; operating assumptions for interconnection studies; consideration of alternative transmission technologies; and ridethrough requirements. 

Acknowledging the changes it made, the commission also extended the compliance deadline from April 3 to 30 days after the publication of Order 2023-A in the Federal Register. 

Commission Acts on 3 Compliance Filings

In separate orders, the commission found Duke Energy had largely complied with Order 2023 but gave Idaho Power and Arizona Public Service lengthy to-do lists. FERC ordered the utilities to file revised provisions within 30 days of publication of Order 2023-A in the Federal Register. 

Duke Energy

The commission found that Duke Energy Carolinas and Duke Energy Progress were fully in compliance but that Duke Energy Florida failed to fully comply (ER24-679, ER24-683). 

It required the Florida utility to modify or defend its definitions of “scoping meeting” and “transmission provider’s interconnection facilities” because they varied from in the commission’s pro forma LGIP, and it said the utility had not fully complied with the order regarding the allocation of cluster study costs and site control.

Idaho Power

The commission gave Idaho Power a mixed grade, faulting it for “various unexplained revisions throughout” its LGIP, pro forma LGIA, SGIP and pro forma SGIA (ER24-10, ER24-1399). 

It cited the utility’s proposed definition of “generating facility” and insertion of “nonrefundable” when describing the $5,000 application fee in its LGIP. 

It also required the utility to make minor changes to its provisions regarding cluster studies and other changes to sections concerning affected-system studies, surplus interconnection service and provisional interconnection service. 

Arizona Public Service

FERC was most critical of APS’ compliance filing, saying the company had proposed “to retain a significant number of existing tariff provisions that deviate from the pro forma interconnection procedures and agreements” adopted in Order 2023 (ER24-330). 

APS said its proposals were justified because the commission approved several APS-specific interconnection changes in a September order — after issuing Order 2023. 

The commission disagreed. “Although the commission previously accepted certain deviations proposed by APS in its queue reform filing, the commission evaluated the queue reform filing under the commission’s pro forma interconnection procedures and agreements in effect at the time — that is, those adopted in Order Nos. 2003, 2006 and 845, without the modifications adopted in Order No. 2023,” it said. “As such, the commission’s findings in the queue reform order have no bearing on whether APS has satisfied its obligation to comply with the requirements of Order No. 2023.” 

The commission said APS had proposed deviations from the commission’s pro forma LGIP and pro forma LGIA regarding the cluster study process “without demonstrating how such deviations satisfy the ‘consistent with or superior to’ standard.” 

It also found APS only in partial compliance in its language on allocation of cluster study costs; network upgrades and interconnection facilities; study deposits; site control; commercial readiness provisions; withdrawal penalties; transition process; operating assumptions for interconnection studies; alternative transmission technologies and modeling; and ridethrough requirements for nonsynchronous small generating facilities. 

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Solar Developer Seeks Inslee’s OK for 60-MW Eastern Wash. Project

A Seattle-based company is proposing its second solar project in southeastern Washington. 

OneEnergy Renewables briefed the Washington Energy Facility Site Evaluation Council (EFSEC) March 20 about its proposed 60-MW solar farm near the Columbia River community of Plymouth in southern Benton County. The Wallula Gap project also could include an optional battery energy storage system not to exceed the facility’s nameplate capacity, EFSEC said. 

The project would interconnect through a line tap to a Benton Public Utility District 115-kV line and then be connected to the Bonneville Power Administration grid at McNary substation in Umatilla, Ore. 

OneEnergy has another 80-MW solar farm, Goose Prairie, due to go online in early 2025 in adjacent Yakima County near the town of Moxee.  

On Wednesday, OneEnergy Associate Director for Development Nathan Stottler told the EFSEC that its Wallula Gap project is eyeing 392 acres of flat, partly rocky pastureland and hoping to complete construction by April 2026.   

In Washington, solar and wind power ventures can seek approval from either the appropriate county government or, after receiving recommendations from EFSEC, the governor. Benton County declared a moratorium on new solar and wind power facilities in 2021, leaving OneEnergy with the option of going through EFSEC for approval of Goose Prairie. (See Inslee Approves 80-MW Goose Prairie Solar Farm.) 

Benton County already opposes a proposed huge and controversial wind farm in the Horse Heaven Hills south of Kennewick. That developer — Scout Clean Energy of Boulder, Colo. — also is going through EFSEC.  

In February, EFSEC decided to set up a two-mile buffer around each known ferruginous hawk nest within the project’s 112-square-mile site. In 2021, the Washington Fish and Wildlife Commission unanimously heightened the status of ferruginous hawks from threatened to endangered. (See Washington Renewable Developer Rankled by Siting Board Alterations.) 

Scout’s plans call for either 222 wind turbines up to 500 feet tall or 141 657-foot turbines along a 24-mile east-west stretch of the Horse Heaven Hills. EFSEC’s Jan. 31 decision potentially would cut up to 116 of the shorter turbines or 73 of the taller ones from the project. The agency granted Scout’s request, giving it until April 30 to continue with the project. 

Gov. Jay Inslee (D) already has approved three solar projects in eastern Yakima County, including the 94-MW Black Rock project 20 miles east of Moxee and the two 80-MW High Top and Ostrea projects just west of the border between Benton and Yakima counties. 

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MISO Members Mull Full Impact of DER Aggregations in Markets

DALLAS — MISO members pondered at Board Week how quickly the full impact of Order 2222 will be felt across the footprint.  

During a March 20 Advisory Committee meeting, WEC Energy Group’s Chris Plante said it’s difficult to pinpoint the contribution of aggregated DERs across MISO because state regulatory authorities have differing views on how DER aggregation programs should look. 

Fresh Energy’s Mike Schowalter also predicted a “scattered approach” among MISO utilities.  

MISO doesn’t yet have FERC’s go-ahead to proceed with its implementation plan. The commission said MISO has a few kinks to work out, namely how it will manage cybersecurity, dispute resolution and reformulating a go-live date sooner than MISO’s initial 2030 target. (See Stakeholders Ask MISO to Share New Order 2222 Go-live Date ASAP.) 

Executive Director of Market and Grid Strategy Zak Joundi said Order 2222 means bringing together “a lot more parties,” and jurisdictions with responsibilities outside of the MISO tariff.  

Minnesota Public Utilities Commissioner Joseph Sullivan said the Organization of MISO States’ annual DER surveys found approximately 12.5 GW of DERs across the footprint, some ripe for aggregations.  

“I think we’re all over the map in terms of expectations,” said ITC’s Brian Drumm, representing MISO’s transmission owners. He said the complexity of the order’s aims is compounded by the fact some technology to harness aggregated DERs is undeveloped. 

Minnesota Public Utilities Commissioner Joseph Sullivan | © RTO Insider LLC

“This is going to take a lot of time. This is a very expansive order. There’s a lot of work to be done that’s kind of nebulous and very broad,” Drumm said.  

“Where there is meat on the bone, where there is money to be made, participants will find their way into the market,” the Union of Concerned Scientists’ Sam Gomberg said. He predicted steady, slow-moving work preparing markets for DERs and then “a rapid, widespread adoption” of rooftop solar, electric vehicles and distributed storage.  

Gomberg said it would be a “missed opportunity” to not prepare and be forced to “scramble” and seek a pause when MISO reaches the described DER tipping point. 

MISO Director Nancy Lange asked if utilities’ distribution systems can handle aggregations efficiently and economically. 

“We’ve taken steps,” Alliant Energy’s Mitch Myhre said, referencing investments in communication systems, distribution upgrades, energy management systems and fiber technology.  

Xcel Energy’s Susan Rossi also said MISO’s transmission owners are investing in advanced metering management systems, calling them the “building blocks” of Order 2222.  

“We’re all in the space of where to invest the money. And of course, we’re sensitive to customer affordability,” Ameren’s Jeff Dodd said. Dodd added that no RTO is far enough along in incorporating DER aggregations in the market to “steal good ideas” from.  

“My sense is technically we’re capable,” Sullivan said, though he added he has reservations about utilities’ preparedness for the supply uncertainties aggregated DER offers will introduce.  

MISO Director Todd Raba said recent instances of demand response gaming in MISO markets begs the question of “who’s going to be the policeman” and discourage fraud in aggregations.  

“It has to be a multilevel responsibility and accountability structure. I think it’s MISO, it’s FERC, it’s state commissions. And that’s not to punt, that’s not to say that it’s no one’s responsibility,” Sullivan said.  

Drumm said he believed that stopping potential exploitation of MISO’s markets by DER aggregations “falls squarely” under the monitoring duties of the Independent Market Monitor.  

MISO will hold discussions on its new Order 2222 implementation date through April via the RTO’s Distributed Energy Resources Task Force. The task force was scheduled to sunset this year but has been extended through 2025.  

The RTO has until May 10 to file an updated implementation plan with FERC.  

“There are meetings we still have on the books before the filing,” Joundi said, encouraging stakeholders to weigh in on MISO’s second Order 2222 compliance filing.  

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MISO Says Rigorous Accreditation Key to Managing Future Market Ops, Reviews Mostly Calm Winter

DALLAS — MISO’s imminent filing for a new capacity accreditation is a crucial first step to prepare for a more complex and challenging future, executives told attendees during March Board Week.  

The added persuasion comes as MISO exited winter with no critical steps taken to maintain reliability.  

Executive Director of Market and Grid Strategy Zak Joundi said MISO’s growing reliability risks mean accreditation should be tied to resource’s output during hazardous periods. The RTO plans to file before the end of March to implement a probabilistic capacity accreditation, where capacity credits will be determined by individual past performance and a resource-class average performance during risky hours for different types of generation. (See MISO: New Capacity Accreditation Filing Imminent.) The accreditation style is marginal, using loss-of-load inputs instead of unforced capacity, and will chip away at solar generation’s capacity credits over the decade until they’re a fraction of what they used to be.  

MISO’s predicted capacity accreditation percentages in summer by 2032 | MISO

“Accreditation is one of the most important signals that we as an RTO can provide our members,” Joundi said.  

“The accreditation MISO is moving towards filing is one of the most important it will make in years,” MISO Independent Market Monitor David Patton agreed.  

“We have some controllable resources, but those are quickly disappearing,” Vice President of Operations Renuka Chatterjee added while talking about mounting risks during winter mornings by 2030.  

Chatterjee said for roughly the past month, MISO has been monitoring low system stability during weekends due to unprecedented renewable output.  

“I don’t want to scare folks. We are OK. We have tools to manage this. … But if we don’t do this work, we will be in worse shape by 2030,” Chatterjee said.  

Winter Storm Performance Improves

MISO appears to be getting well versed in steady operations amid increasingly volatile weather.  

Executive Director of System Operations Jessica Lucas said the RTO had no trouble handling a mild winter except for mid-January’s footprint-wide Arctic blast. The cold front delivered MISO’s 105.9-GW winter peak on Jan. 17. On that day, MISO South set a new winter peak at 32.6 GW.  

The footprint also set a new wind generation peak of 25.7 GW on Jan. 17, where wind served 30% of load and buoyed the system above maximum generation alerts. (See MISO Holds Steady in Mid-Jan. Storm with Help from Wind.)  

“It does look like we’re creating a pattern. Three years and every year, another 100-year storm,” Lucas said, referencing “déjà vu” winter storms in February 2021 and December 2022. 

However, for this winter storm, MISO experienced just 5 GW in incremental unplanned outages, compared to 15-20 GW in added forced outages during the previous comparable winter storms. 

MISO Director Barbara Krumsiek commended the grid operator for improved performance during the deep freeze.  

“The first one, the first time is a shock to the system. But to see how MISO and its members have adjusted is gratifying,” Krumsiek said.  

Lucas said MISO’s better prep is due in part to its availability-based accreditation that’s been in place for thermal generation for about two years.  

She also said MISO’s new uncertainty management model flagged the winter storm span as high-risk days in advance, leading operators to increase the RTO’s short-term reserve requirements. Requirements averaged 5 GW over the event and climbed as high as 6 GW.  

Patton praised MISO’s progress on uncertainty modeling. He said MISO has been more dynamic in procuring reserves, which mitigates risks and ultimately lowers costs. 

“This is the kind of model that I wish Texas would incorporate,” he said. “I think [MISO is] on the forefront here.”  

At the Gulf Coast Power Association’s early March MISO-SPP conference, Executive Director of Market Operations J.T. Smith also said MISO’s model augmented by machine learning did a solid job predicting which generation showed up during the mid-January Arctic blast.

Smith said a pressure gradient over MISO Midwest could mean an up to 10 GW difference in wind production and that a 50-mile discrepancy in a winter storm’s path over MISO South causes vast differences in demand.  

“Our entire system is weather dependent,” Smith said.  

MISO also recently secured a $3 million grant from the U.S. Department of Energy to explore more machine learning and modernize control room operations. 

Patton said the RTO dramatically reduced its usual manual redispatch during the cold snap, instead allowing its transmission constraint demand curve to price generation to manage flows on the system. Patton said compared to the winter storm a year ago, this time MISO operators took 84% fewer out-of-market actions to manage congestion. He said if the latest storm had happened a few years ago, MISO operators probably would have made more commitments than necessary. 

“Overall, the management of the system during Winter Storm Heather was really good,” Patton said. “MISO exercised good judgment in commitment decisions and avoided unnecessary uplift, deferring decisions until necessitated by offered lead times.” 

Patton said MISO’s real-time revenue sufficiency guarantee payments totaled just $5 million, compared to the almost $90 million incurred in the February 2021 winter storm.  

MISO Director Phyllis Currie joked that she heard Patton complimenting MISO’s actions repeatedly. 

“Excellent. Then I must have missed something,” Patton said with a laugh.  

The IMM said over the winter, regional transfer generally flowed from South to Midwest. However, when the cold blast struck, flows shifted from Midwest to South.  

The IMM said drought conditions in the Manitoba Hydro service territory caused South-to-North flows over the winter. Ordinarily, MISO imports power from the hydroelectric utility. Members of late have been consistently exporting power across the border.  

Total congestion over the mid-January storm totaled almost $153 million, Patton reported.  

Patton said while overall congestion was more manageable during the latest winter storm, MISO did receive incorrect transmission flow data from a market participant, contributing to a transmission violation and MISO having to declare a safe operating mode to redispatch generation in PJM to get flows back in line with the rating.  

“This raises substantial concerns regarding the information some participants provide to MISO, which can impact reliability,” Patton said. “The same participant failed to provide SCADA data on a nuclear unit, which impacted MISO’s response to it tripping offline in mid-February.”  

Patton declined to name the market participant.  

“If this was going on, this would make me very unhappy, trying to operate the system without full and accurate data from all participants,” Patton said. He flagged the issue as a “big concern.”  

He also said that over Jan. 15 and 16, MISO “effectively ran out of generation” in the Southeast Texas load pocket; the area racked up severe congestion and prices jumped to $1,500/MWh. Patton said the situation subsided when a generator in the area that’s “almost entirely connected to ERCOT” decided to direct its output into MISO.  

Patton singled out the generator for consistently failing to show up in MISO during times of need despite participating in its capacity auctions. Patton said MISO should strike that generation from its capacity totals, and that the RTO should make the adjustment before its upcoming capacity auction, so it doesn’t count on generation that won’t materialize.  

MISO set a solar output record of 4.4 GW on Feb. 19, where panels managed 6% of load. The grid operator has had 12 new solar peaks over the past year as members swiftly add solar installations.  

MISO also said wind generation made its first appearance in the South during the winter quarter, with the debut of the 185-MW Delta wind farm in Tunica, Miss. A 180-MW wind farm, Nimbus, is planned to begin operations next year in rural Arkansas. 

Looking ahead, MISO said even high demand over the spring shouldn’t present challenges. Although MISO expects demand could top out at nearly 107 GW in May, the grid operator’s 113.6 GW of cleared capacity throughout spring appears sufficient. 

MISO is also planning for a rapid drop in output and then recovery among its growing solar fleet April 8, when the solar eclipse tracks across its footprint. Lucas said MISO likely will need greater-than-usual ramping capability and more congestion management efforts that afternoon. 

MISO spring capacity projections in GWs | MISO
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IMM Tells MISO to Do More to Curb Fake DR Schemes

DALLAS — MISO’s Independent Market Monitor told the Board of Directors on March 19 the RTO must crack down on confirmations to prevent more phony demand response from infiltrating its markets.  

Monitor David Patton said penalties for the string of demand response schemes have eclipsed $100 million. FERC in February put the squeeze on an obscure, Texas-based LLC formed to sell in-car ketchup holders to the tune of $27 million for offering faux load reductions. It was the third time recently a company was caught manipulating MISO’s demand response market and collecting unjustified payments. (See FERC Catches Ketchup Caddy Co. in Another Fake DR Scheme in MISO.) 

“When you move demand to the supply side, there’s certain things you need to do … to validate the demand response is actually real,” Patton said during a Markets Committee of the MISO Board of Directors meeting. 

Patton said he’s working with MISO to “remove vulnerabilities” from its ruleset regarding DR registrations and validations. He said the RTO must dedicate more resources to authenticating DR capabilities.  

MISO directors discussed recent instances of apparent DR fraud in a nonpublic session following the MC meeting. No board members stated their opinions publicly on the scams during Board Week.  

WEC Energy Group’s Chris Plante suggested MISO’s Advisory Committee schedule a discussion on the Ketchup Caddy situation and where responsibility for authenticating demand response market participants ultimately lands.