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November 16, 2024

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NJ Eyes Rules to Protect, Gather Advanced Metering Data

New Jersey is studying how to set data-gathering rules to ensure that the growing implementation of advanced metering infrastructure (AMI) helps ratepayers cut energy use and support efforts to meet the state’s ambitious clean energy goals.

The state’s Board of Public Utilities (BPU) will hold a second hearing on Sept. 6 into its straw proposal intended to ensure that ratepayers and other stakeholders can get speedy, accurate data on which to make energy decisions while protecting the privacy of consumers and securing the system.

State officials believe AMI is an important element to implementing Gov. Phil Murphy’s Energy Master Plan, which sets a state goal of 100% clean energy by 2050. It calls AMI a “foundational component of a modernized electric distribution grid” and describes it as “a prerequisite of many additional clean energy objectives.”

AMI is the use of “smart” meters that can compile data on a ratepayer’s energy use and transmit it to the user or third party, often in real time. Analysis of the data can help the ratepayer adjust their energy use, facilitating changes such as shifting the time of day for completing tasks to when energy is cheaper, halting some practices or allowing the user to switch away from high energy-consuming appliances.

The first utility in the state to implement an AMI strategy, Rockland Electric Co., installed about 74,000 smart meters by 2019. The state expects its other three utilities to deploy more than 3.9 million smart meters over the next five years.

Benefits of AMI

The straw proposal, released a year ago, would create a standardized system of rules that govern how utilities handle issues such as data sharing, data access, data privacy and billing reconciliation. The state’s four utilities would each be required to file data access plans to implement the rules.

AMI “holds the potential to be an integral part of New Jersey’s clean energy transition, enhance retail competition and efficiencies, and enable customers to better understand and control their own energy usage,” the proposal says.

The straw proposal emphasizes that the data, although often collected by the utility, are owned by ratepayers, who should control who can access them and whether that should include third parties. The BPU’s plan recommends the use of the “Green Button Connect” system, a standardized, relatively user-friendly system through which ratepayers can access their own data through a green button on their utility company’s website. The proposal also would require utilities to follow standard cybersecurity measures to protect the data.

Metrics that should be collected, according to the proposal, include: total usage and demand in kilowatt-hours, the number of customers who access the data, and how many customers sign up for energy-saving tools, energy-usage information and saving tips.

Speakers told the first hearing on the proposal Aug. 16 that the speed at which data become available is important to ensuring their value and to keeping consumers focused on their energy usage.

“Energy data is a highly fungible commodity whose value is maximized when accessed and interpreted shortly after the energy consumption,” said Christopher Oprysk, an engineer at the BPU who presented parts of the proposal at the hearing. “Consumers are more likely to respond with behavior changes if the data reflects recent consumption patterns and more closely ties [it] to cause and effect.”

The proposal argues that “billable data,” which are collected by the utilities to calculate ratepayer bills, should be available within 48 hours and customers should be provided with an energy monitoring device that would make available unvalidated data within 15 seconds, which could be accessed through a home area network.

Murray Bevan, a lobbyist for several energy suppliers, including NRG Energy and Vistra, echoed the point, telling the BPU that rapid access to data is critical.

“If I run my dishwasher at 4 in the afternoon, or I run it at 10 at night, there’s like a 40% difference in the price of running it,” he said. “So if I really need the clean dishes for dinner at 6 or 7, OK, I’ll go ahead and run it. But if I can wait until 10, that’s a significant price win.”

“Getting the data as close to the real time usage as possible, is the most valuable,” he said. “If I’m making this decision on Monday, and I’ve learned about it, that I should have run the dishwasher at 10, on Tuesday or Wednesday, obviously that’s not as valuable to the customers.”

AMI Implementation Surge

The BPU in January gave approval to a plan by Public Service Electric and Gas to invest $700 million over the next four years to provide smart meters to its 2.3 million electricity customers. The company at the time said the move would “help expedite electric service restorations when severe weather strikes, help customers increase their home energy savings and improve service quality.”

In July 2021 the board approved a plan a plan by Atlantic City Electric to spend $177 million on installing 565,000 smart meters. And the state’s fourth utility, Jersey Central Power & Light, has a plan before the BPU to spend $360 million on AMI.

Yet the state’s adoption of AMI has lagged, even as other states have embraced the technology. There were 94.4 million advanced meters in operation as of 2019, the latest that figures are available, according to FERC’s annual Assessment of Demand Response and Advanced Metering report released in December. That accounted for 60.3% of the meters of all types operating in the country and was an increase of 8 million smart meters over the year before, the report said.

The Mid-Atlantic region had the second worst penetration in the nation, with only 37.4% of the meters being advanced, the report said. The worst was New England, with 22% penetration, while the highest penetration was in the West South Central Region, which includes Texas, and the Pacific region, both with about 74% penetration.

Yet even those areas in which AMI penetration is high, the technology may not be fully used, according to a study that Mission:data, a nonprofit advocacy organization that works to promote AMI usage, is set to release next week. More than a decade after the federal American Recovery and Reinvestment Act (ARRA) disbursed $3 billion for AMI projects, “most of the data-access benefits promised to customers have been deactivated,” the report says. Only about 2.9% of the 17.4 million advanced meters funded by the program are enabled, the report says.

Still, New Jersey’s slow uptake could end up helping the state, said Michael Murray, president of Mission:data. The state can learn from projects in other states where “customer benefits of smart meters have not materialized,” he said in an interview with NetZero Insider. And the state’s program could be bolstered by the recently enacted Inflation Reduction Act, which includes funds that can be used for AMI, he said.

While some consumer advocates are skeptical that the benefits from AMI are worth the investment, a dozen studies have shown that “6 to 18% energy savings are possible when consumers have easy, electronic access to their meter data,” he said. Aside from helping customers cut energy use, AMI data can help them buy the right size of appliance they need based on actual electricity use and can help with the purchase of energy-efficient equipment such as heat pumps.

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MISO Recommends Lower Distribution Factor to Address Congestion

To cut down on its surging congestion, MISO is suggesting a tighter limit on how much new generation can affect the surrounding grid without triggering more network upgrades.

The grid operator announced it is considering halving new generation’s allotted distribution factor impact on transmission from 20% to 10% for its basic level of interconnection service, called energy resource interconnection service (ERIS).

Some MISO members maintain that interconnecting generators are unacceptably raising congestion and a narrower distribution factor threshold would keep runaway congestion in check by flagging a need for more transmission upgrades.

MISO said a preliminary analysis showed that lowering the distribution factor for ERIS to 10% identified “several” new network upgrades in its annual interconnection queue cycles, “the majority being in the 69 to 161 kV voltage range.”

Interconnection customers can either elect to secure ERIS, or the higher-quality network resource interconnection service (NRIS), which ensures that the entire installed capacity of resources is deliverable. NRIS is generally more expensive than the unguaranteed ERIS.

MISO said ERIS elections from new generation “can lead to more congestion on the transmission system.” It said a lower distribution factor cutoff could result in fewer system reliability issues and have more interconnection customers sharing in network upgrade costs.

The RTO now faces billion-dollar congestion costs on a quarterly basis. MISO’s long-term transmission plan is set to assuage some of that congestion, but the first in-service dates of the 18 new lines are at least eight years out.

Meanwhile, the grid operator is again bracing for a historic level of interconnection requests in its 2022 queue cycle. During an Aug. 30 transmission cost allocation meeting, MISO’s interconnection team estimated the RTO will field about 700 new interconnection requests totaling about 100 GW in a few weeks.

MISO staff also said they’ve been receiving complaints from new generators that have interconnected but cannot get their output delivered on the system due to transmission congestion.

Some of MISO’s clean energy advocates have said lowering the distribution factor threshold seems punitive to renewable energy, which makes up the overwhelming majority of MISO’s interconnection queue.

At a mid-August Interconnection Process Working Group, Xcel Energy’s Randy Oye said increased expenses for new generation isn’t a valid argument against lowering the distribution factor threshold. He said if a project stands to affect lines by 20%, then the project’s business case might need to be reexamined.

“The load is going to pay $10 billion for transmission. I think a fair question is: what should generation pay?” he said, referring to the cost of MISO’s recently approved long-range transmission portfolio.

Stakeholders asked for some sort of MISO demonstration that lowering the distribution factor threshold will in fact reduce congestion. They also criticized MISO for concocting a policy change in secret before bringing a proposal to a stakeholder meeting.

MISO’s stakeholder community is again set to again debate a stricter distribution factor at an Oct. 10 Interconnection Process Working Group meeting.

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MISO Cancels Hartburg-Sabine Competitive Project

A MISO staff planning committee has determined that MISO South’s only competitive transmission project, the $130 million, 500-kV Hartburg-Sabine Junction project in East Texas, is no longer necessary.

The decision wasn’t surprising. MISO has been warning for months that its analysis indicated that the project was no longer helpful to the system. (See MISO on Verge of Cancelling Hartburg-Sabine Tx Project.)

The project’s cancellation comes as the 5th U.S. Circuit Court of Appeals Tuesday ruled that Texas’ right-of-first-refusal (ROFR) law violates the U.S. Constitution’s dormant Commerce Clause. (See 5th Circuit Finds in Favor of NextEra’s ROFR Appeal.)

Brian Pedersen, senior manager of competitive transmission administration, said the RTO is evaluating the opinion for possible impacts to Hartburg-Sabine. However, “the opinion and order does not change the planning analysis,” he told stakeholders Wednesday during a Planning Advisory Committee meeting.

Pedersen added that MISO isn’t planning to conduct any more economic or reliability analyses on the project. He said studies have already shown the project has “near-zero” production cost benefits and did not uncover any transmission system issues without the line.

The grid operator said the project’s benefits dissolved because of recent Entergy generation additions near the line’s route. The utility brought the 993-MW Montgomery County Power Station online in 2021, and it intends to construct the 1.2-GW natural gas- and hydrogen-powered Orange County Advanced Power Station by 2026.

MISO approved the market efficiency project as part of its 2017 Transmission Expansion Plan, based on expectations it would alleviate congestion, ease import limitations and allow access to lower cost generation for customers in the chronically congested West of the Atchafalaya Basin and western load pockets in Entergy’s MISO South footprint.

“It’s been a little over four and a half years since the project was approved,” Pedersen reminded stakeholders.

In 2018, MISO selected NextEra Energy Transmission Midwest’s bid for a new 23-mile, 500-kV transmission line, four short 230-kV lines and a new 500-kV substation. NextEra’s proposal beat 11 other competitors. (See NextEra Wins Bid to Build MISO’s 2nd Competitive Project.)

However, Texas later passed a law in 2019 giving incumbent utilities ROFRs for any projects built in the state. With NextEra unable to secure permitting for construction and the 2023 in-service date approaching, MISO this year initiated its variance analysis, a process used to reanalyze projects that experience material changes. Following the analysis, the RTO had two choices: cancel the project or reassign it to a new developer.

“MISO always has deference to states’ rights in these types of matters,” director Mark Johnson explained in 2019.

MISO’s bid selection report is now considered moot. The grid operator now plans to file with FERC in the fourth quarter to terminate its selected-developer agreement with NextEra.

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Maine Court Ruling Gives New Life to Contentious Transmission Line

Maine’s highest court on Tuesday ruled that a referendum blocking the New England Clean Energy Connect (NECEC) transmission line may have been unconstitutional, reigniting hopes that the fiercely opposed project could get built after all.

In a 39-page ruling, the Maine Supreme Judicial Court found that part of the ballot question could be invalid because it retroactively applies new laws to the certificate of public convenience and necessity obtained by the project’s developer Avangrid (NYSE:AGR) and its subsidiary Central Maine Power.

It sent the case back to the Maine Business and Consumer Court for “further proceedings consistent with this opinion.”

The ruling is the latest twist in a consequential saga that some clean energy advocates say will shape the future of New England and determine how quickly the region can wean itself off fossil fuels. The line, which would bring energy from hydropower plants in Quebec into New England and is central to Massachusetts’ clean energy plans, has been at the center of legal and political battles for years.

It received a signoff from the federal government in early 2021, only to be shot down by Maine voters in a referendum later that year in which 59% voted to ban the construction of “high-impact” transmission lines in the area and require approval from the legislature for future such projects.

The constitutionality of that ballot initiative has been the last-gasp hope of the project’s developers, and Maine’s highest court came to their aid on Tuesday.

“Our analysis and conclusions are not based on the wisdom of either the project or the [ballot] initiative,” the five-judge panel wrote. But the initiative would “infringe on NECEC’s constitutionally protected vested rights” if the project can show that it engaged in “substantial construction” on the authority granted by the certificate it was granted before the initiative was approved by Maine voters.

ClearView Energy Partners called the ruling a “significant win” for NECEC, but it noted that there are other risks pending.

“We view today’s opinion as constructive to CMP’s plans to complete the project, but the project developer has not yet overcome all its legal challenges,” ClearView’s analysts said.

Those include a separate case about a lease from the Bureau of Parks and Lands, a suspended permit from the Maine Department of Environmental Quality, and judicial challenges to two federal permits by environmental groups.

But those remaining challenges didn’t stop Avangrid from breathing a sigh of relief.

“This unanimous decision by the law court is a victory for clean energy expansion, transmission development and decarbonization efforts in Maine, New England and across the country,” Avangrid said in a statement.

The company said the project has faced opposition from fossil fuel-fired generators at every step.

“It is time to move away from the status quo fossil fuel companies who will undoubtedly continue their fight to maintain a stranglehold on the New England energy market,” Avangrid said. “These companies have fought this clean energy project in every legal manner possible, filing challenge after challenge in a desperate effort to hold onto their share of the market. Maine’s highest court has rejected their latest challenge as unconstitutional.”

The ruling was also celebrated by the transmission trade group WIRES.

“Today’s decision by the Maine Supreme Court will hopefully set the important NECEC project back on track, although with likely further delays,” WIRES Executive Director Larry Gasteiger said, calling the project a “poster child for how difficult it is to get needed transmission built.”

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Northwest States Collaborate to Win Hydrogen Hub

Washington, Oregon and Idaho are preparing a joint proposal to become a regional hydrogen manufacturing and distribution hub.

The three state governments — acting as leaders of the public-private Pacific Northwest Hydrogen Association — aim to have a proposal ready sometime in September to submit to the U.S. Department of Energy to obtain part of $8 billion in federal funding being made available to develop hydrogen hubs nationwide.

On Monday, the association announced that its 18-member board elected Washington Department of Commerce Director Lisa Brown as its chair and Oregon Department of Energy Director Janine Benner as vice-chair. Idaho’s government is represented in the group’s Advisory Committee.

“We understand how green hydrogen fits into a modern, decarbonized economy that is possible today — no other region is as advanced in this area,” Brown said in a press release.

“This work will lay a foundation for this important decarbonization fuel in our region — one that can help us meet our mission to shape an equitable clean energy transition for Oregon and beyond.”

Other interests represented on the board include the Douglas County Public Utility District, Tacoma Power, several labor unions, some hydrogen and environmental organizations, Amazon, BP America, Puget Sound Power, plus the Chehalis and Cowlitz tribes. Several research organizations and labs, including the Pacific Northwest National Laboratory, also participate in the association.

The association’s board also includes a representative from Australia-based Fortescue Future Industries, which is exploring building a green hydrogen plant on the site of a disused coal mine in Centralia, Wash. (See Australian Company Eyes Wash. Coal Mine as Green Hydrogen Site.)

This alliance wants to tap into the $8 billion fund that DOE has set aside to create four to eight regional hydrogen hubs across the nation. Each hub would get $1 billion to $2 billion. Washington, Oregon and Idaho are aggressively pursuing that money.

DOE expects to receive roughly 100 proposals by September. No timetable is set for the agency’s decisions on how to allocate the $8 billion.

In Washington, one hydrogen manufacturing plant owned by the Douglas County PUD is scheduled to go online in East Wenatchee in mid-2023. The Port of Seattle is also studying whether it wants to get into hydrogen manufacturing and distribution. Refueling stations for hydrogen-powered vehicles are in the works for East Wenatchee and the transit authority in Chehalis and Centralia

Meanwhile, Obsidian Renewables of Lake Oswego, Ore., plans to build hydrogen production plants at existing industrial parks in Hermiston, Ore., and Moses Lake, Wash. These would supply a proposed pipeline system that would terminate at points in The Dalles, Pendleton and Prineville in Oregon, and in Wenatchee and Spokane in Washington. Another pipeline would extend to Lewiston, Idaho. One connecting pipeline would go through the Tri-Cities, which is the second-most populated area in eastern Washington behind Spokane. (See Company Looks to Build Hydrogen Projects in Eastern Ore., Wash.)

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FERC Issues Deficiency Letter on PJM Queue Overhaul

FERC issued a deficiency letter Tuesday seeking more information on PJM’s proposed overhaul of its interconnection queue process (ER22-2110).

With a ballooning backlog in its interconnection process and a sharp increase in new service requests, PJM is seeking to switch from its current “first come, first served” system to a “first ready, first served” queue. The proposal would cluster service requests together for both interconnection studies and cost allocation and advance applications making demonstrable progress toward operability. (See PJM Files Interconnection Proposal with FERC.)

The Aug. 30 letter from FERC’s Office of Energy Market Regulation asks for further information on several points of the tariff revision, largely having to do with how the new procedures would operate and comply with past FERC orders. A response is due from PJM within 30 days.

The letter questions if grouping all applications from Oct. 1, 2021, with those received through the processing of the first new cycle could create a risk of the first wave of projects evaluated under the new system becoming “unmanageably large” and how the RTO would address that possibility.

The removal of two sections of the tariff related to reporting and penalties for PJM should it fail to complete a set percentage of transmission service request studies within a certain timeframe caught FERC’s attention, with the commission seeking an explanation of how the removal would be “consistent with or superior to” the current requirements under Order 890.

The letter also seeks more information on the RTO’s plan to consolidate interconnection procedures for both small and large generators.

Staff also asked the RTO to explain how it will determine whether a request for long-term firm service can be studied as part of the planning process for bulk transmission supply in PJM or whether special impact studies must be completed.

And it asked for clarification of PJM’s proposal to allow a project developer to change the project site from one location to an “adjacent parcel,” asking whether they must be contiguous or merely in the same geographic area.

Tariff Revisions Supported by Stakeholders

The revisions to PJM’s tariff were submitted to FERC June 14 after receiving strong endorsement from the RTO’s stakeholders in April.

The RTO has stated that its proposal is comparable to the interconnection processes employed by SPP, MISO and PacifiCorp. The new system would add multiple decision points at which applicants would be required to make readiness deposits and meet other requirements to continue.

Currently, less than 20% of applications make their way through the queue and become operational.

Not all projects drop out because of the length or difficulty of the process. Many projects are speculative “price discovery” requests submitted to determine where interconnection costs are least expensive. 

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NYISO Details 2023 Budget & Compensation Updates

NYISO is proposing a $32 million project budget for 2023, a $5 million reduction from this year’s spending.

NYISO’s Brian Hurysz, who presented the final project recommendations for the 2023 budget to the Budget and Priorities Working Group (BPWG), said 13 of the 24 projects that had been identified as stakeholder priorities were included in the spending plan.

The $31.98 million budget includes $13.7 million for labor, $9.7 million for capital and $8.5 million for professional services, $5.2 million lower than the 2022 project budget of $37.2 million. The 2022 budget increased project spending by $10.7 million over 2021 largely because of the Alternate Control Room Renovation project, which was deferred from 2021, and the Distributed Energy Resource Integration project.

The market and enterprise budget recommendations were $11.36 million and $20.62 million, respectively. 

In addition to deferring 11 of the 24 proposed market projects, including the duct firing modeling that NYISO desired, the ISO is recommending cost savings or scope changes for some projects:

  • The Distributed Energy Resources (DER) Participation Model will be delayed, with deployment planned later in 2023. The cost of the project has increased, and the operational enhancements have been reduced.
  • Storage as Transmission, requested by stakeholders, will be limited to “issue discovery” — education sessions and identification of potential solutions for future ranking — in 2023.
  • Capacity Resource Interconnection Service (CRIS) Expiration Evaluation & CRIS Tracking: CRIS Tracking will be deferred to 2024; CRIS Expiration Evaluation will develop CRIS Tracking requirement updates and be implemented with CRIS Tracking in 2024.
  • FERC Order 2222 Compliance: Scope of the project has increased based on updated information from FERC. The ISO recommends changing commitment from completed documentation of Functional Requirements (FRS) to Market Design Concept Proposed (MDCP).
  • Balancing Intermittency & Dispatchability and Fast Response Product: The ISO proposes combining some of the Dispatchability and Fast Response scope with the Balancing Intermittency, which was recommended in Potomac Analytics’ State of the Market (SOM) project.
  • Unified Communications Platform: The ISO recommends deferring the work until 2024, saying the equipment to be replaced is not end-of-life in 2023.
Proposed market projects (NYISO) Content.jpgNYISO is recommending deferring 11 of the 24 proposed market projects for 2023 and cost savings or scope changes for others. | NYISO

 

NYISO said stakeholder feedback on the budget can be emailed to Hurysz.  

The ISO’s full 2023 draft budget will be presented at the Sept. 15 BPWG meeting and the Sept. 28 Management Committee meeting.

Compensation Benchmarking Study Boosts Pay for 300 ISO Staffers

NYISO will spend $2.5 million in 2022 to raise the salaries of about 300 non-executive employees in response to a benchmarking study commissioned to address increasing attrition.

NYISO Chief Financial Officer Cheryl Hussey said the ISO hired consulting firm Mercer to conduct the study after seeing an increase in attrition and the number of people rejecting the ISO’s job offers.

Cheryl Hussey (NYISO) Content.jpgNYISO Chief Financial Officer Cheryl Hussey | NYISO

Mercer reviewed compensation data on 525 employees in 247 job titles and found that certain positions — including entry-level grid operators, engineers, software developers, IT security and infrastructure analysts and technical specialists — “trended significantly below the market,” Hussey said.

The ISO agreed to spend $2.5 million to raise “about 300” such employees to the mid-point of their peer group, retroactive to July 1, she said. The cost of the adjustments will be about $5 million for 2023.

The ISO will use nearly half of its $10.7 million 2021 budget surplus to fund these raises and a prior 3% raise given to non-executive staff retroactive to Jan. 1.

Hussey said the ISO would continue monitoring market trends and adjust salary levels again if warranted. “More recently we have had more success in our recruiting. Our vacancy rate is down. But it’s really soon to show a significant change resulting from the latest salary adjustments,” she said.

Barring additional compensation adjustments, the remaining $5.7 million from 2021’s budget surplus would be used to pay down the principal on outstanding debt, which is expected to total $82.5 million at the end of 2022.

Four Projects in 2023 Budget from Consumer Impacts Analysis

The ISO’s Tariq Niazi said that the ISO is recommending four projects be included in the 2023 budget based on its consumer impact analysis:

  • Balancing Intermittency (SOM): The project will examine existing ISO market structures and rules to help identify changes needed to maintain system reliability, while addressing the state’s climate goals cost effectively.
  • Locational Capacity Requirements (LCR) Optimizer Enhancements: Will seek improvements to the LCR methodology to improve stability and transparency.
  • Long Mountain PAR Operating Protocol: The ISO will develop an operating protocol with ISO-NE for the phase angle regulator (PAR) planned for the Long Mountain-Cricket Valley 345-kV intertie, an upgrade from the AC Public Policy Segment B project.
  • Modeling Improvements for Capacity Accreditation (SOM): Continues the work of the Improving Capacity Accreditation project to allow consideration of reliability risks such as correlated fuel unavailability and long start up notifications not modeled by the current resource adequacy analysis software.

The ISO looks for projects that are anticipated to have a net production cost impact of $5 million or more per year; have an impact of more than $50 million per year on consumer energy or capacity market prices; incorporate new technologies into ISO markets for the first time; support a new type or category of market product; or create a mechanism for out-of-market payments for reliability.

Stakeholders expressed skepticism about the ISO’s proposal to improve the modeling used by the resource adequacy analysis software GE MARS. Stakeholders said this proposal “missed the mark” since GE MARS represented such a small amount of the total resources used by NYISO. In response, Niazi stated that he would take these concerns back to his team to reevaluate. But he stressed that having accurate accreditation calculations was critical to reducing costs and improving reliability.

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FERC Rules for SPP in AECI Dispute

FERC last week ruled in favor of SPP in its dispute with Associated Electric Cooperative, Inc. (AECI) over emergency energy transactions during the February 2021 winter storm, finding that the RTO properly compensated the cooperative in accordance with its tariff (EL22-54).

In its Aug. 22 order, the commission also granted SPP’s request that FERC assert exclusive or primary jurisdiction over the emergency energy sales from AECI. FERC ruled the emergency transactions were made under a commission-jurisdictional tariff and said, “Therefore, the sales fall within the commission’s jurisdiction to regulate.”

SPP filed the request in April, asking FERC to act expeditiously to preserve its exclusive jurisdiction over the issues in dispute, given that AECI took its complaint in February to the U.S. District Court for Western Missouri (6:22cv3030). (See “SPP Takes AECI Dispute over Winter Storm Charges to FERC,” SPP Briefs: Week of May 2, 2022.)

At issue is SPP’s compensation for AECI’s emergency assistance during the winter storm. The Missouri cooperative sold power into SPP’s real-time balancing market and submitted respective tags for the transactions. The RTO settled each of AECI’s transactions over Feb.15-19 using the real-time balancing market locational marginal pricing.

The cooperative is seeking to recover $37.64 million from SPP for the emergency power it provided during the storm. That includes $29.4 million for the costs to provide the power and $8.24 million in day-ahead residual unit commitment make-whole payments SPP has charged the cooperative.

SPP’s Market Monitoring Unit intervened in the docket and asserted that FERC “unquestionably has primary jurisdiction” over the amounts SPP paid to AECI for emergency energy. The Monitor said that contracts for wholesale power sales must be filed at FERC and that there are no oral agreements for wholesale power sales. It also argued that the emergency energy transactions were not oral agreements but instead were conducted under the SPP-AECI joint operating agreement and the RTO’s tariff.

In a separate order, FERC denied AECI’s waiver request of SPP’s 365-day limitation period for modifications to settlement statements in its attempt to reach a settlement with the grid operator (ER22-2136).

The commission had twice previously granted AECI 60-day extensions to allow extra time to reach a mutually agreeable resolution with SPP over its costs to supply the RTO with emergency energy during the storm. However, it said AECI’s latest request did not address a concrete problem, as required by FERC’s criteria for waivers.

The cooperative said its latest request would have given it and SPP more time to resolve the ongoing dispute. The commission noted that SPP said the payment dispute remains unchanged and that the grid operator’s view was that no progress can be made.

Wind Farm’s Appeals Denied

FERC last week also rejected Salt Creek Solar’s request for a waiver requiring SPP to reinstate the company’s interconnection queue position and dismissed a complaint alleging the grid operator violated the Federal Power Act (FPA) and its tariff by requiring Salt Creek to post an excessive amount of financial security to maintain its queue position (ER21-2878, EL22-11).

Salt Creek said it submitted an interconnection request in 2017 for a 228-MW solar generating facility in Nebraska. It said it didn’t hear back from SPP until October 2020 — when it was allocated $146 million in network upgrade costs — after the RTO cleared its queue backlog. Salt Creek said a modeling error reduced that amount to $54 million, but it was revised again to $184 million when SPP published its second phase results.

The developer contended that the revised results required Salt Creek to post a $35 million deposit, identical to what it owed after the second phase. It said SPP continued to process higher-queued interconnection requests under its prior processes and that numerous withdrawals occurred. In April 2021, SPP notified interconnection customers that the study cluster would need to be restudied  because of the withdrawals, Salt Creek said.

The grid operator eventually notified the developers that their request was deemed to have been withdrawn because Salt Creek did not pay the deposit within the required time.

FERC found in its Aug. 22 order that Salt Creek’s request for waiver to cure its non-payment after receiving notice of its deemed withdrawal was retroactive and prohibited by filed rate doctrine.

The commission also denied Salt Creek’s complaint that SPP had violated the FPA because the wind farm’s developers did not meet their burden under the act to demonstrate that the RTO had violated its tariff or the FPA.

Commissioner Mark Christie concurred in a separate statement, pointing to FERC’s 2021 order that granted Lookout Solar Park, part of the same cluster with Salt Creek, a waiver to pay its financial security after the restudy’s results were available. He said, “Unsurprisingly, the commission is now faced with having to grant an untenable number of waiver requests or deny the same relief to other customers, like Salt Creek, that may indeed be similarly situated.”

Quoting former Congressman Barney Frank (D-Mass.), Christie said, “The biggest lie in politics is when a politician says, ‘I hate to say I told you so,’ because, as Frank put it, ‘Everybody loves to say it.’”

“I told you so,” Christie concluded.

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FERC Fines CPower $2.5M over ISO-NE Capacity Payments

Demand response aggregator CPower has agreed to pay a $2.5 million penalty after FERC’s enforcement division found the company took capacity payments in violation of ISO-NE rules (IN22-7).

The violations stemmed from the use of ISO-NE’s Price Responsive Demand (PRD) structure, implemented in the Forward Capacity Market in 2018.

Under PRD, an active demand capacity resource (ADCR), made up of one or more demand response resources (DRRs), can obtain a capacity supply obligation (CSO) and receive capacity payments.

Importantly, they’re then also required to submit demand response offers from the associated resources into the region’s day-ahead and real-time markets at levels equal to or greater than their CSO.

Between 2018 and 2019, CPower failed to do so, FERC found.

“The deficiencies between CPower’s CSOs and DROs [demand reduction offers] … grew from a minimum of 5.5 MW in June 2018 to a minimum of 33.2 MW in February 2019,” the enforcement filing says.

The company earned nearly $2.5 million in capacity payments that did not have associated DROs, FERC found. And an “individual within substantial authority personnel at CPower” was aware that some of its resources were offering at levels less than their capacity obligations, FERC said.

FERC’s Office of Enforcement started looking into the discrepancy after a referral from the ISO-NE Independent Market Monitor, according to the agency.

In response to the IMM’s initial inquiry, CPower attributed some of the differences to new demand response assets that “did not materialize.”

But FERC found that CPower had violated the ISO-NE tariff, and the company agreed to pay a civil penalty of $2.54 million and disgorge $2.46 million in earnings.

According to the FERC filing, CPower has hired a senior director of regulatory and government affairs and a senior vice president of regulatory affairs in the last year to improve its compliance program.

CPower confirmed with RTO Insider that it settled with FERC, saying, “While today’s outcome stems from the interpretation of what was at that time a new tariff for which there was no precedent, we appreciate that FERC has confirmed that there was no intentional violation and acknowledged the strength of CPower’s compliance program.”