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November 1, 2024

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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.”

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Counterflow: Vampire Power

tesla powerwallSteve Huntoon | Steve Huntoon

This ad from the local utility caught my eye. It’s from Delmarva, a subsidiary of Exelon, the largest utility company in the country.[1] The idea is to unplug appliances not in use so as not to use electricity in “standby” aka “sleep” aka “idle” aka “inactive” aka “phantom” aka “always-on” mode. Vampire power.

Who wouldn’t want to learn more? So I went to delmarva.com/peakmd, and from there to the details page, where the first specific tip is: Unplug unused electrical devices when you leave a room. Chargers use energy when left plugged in, even after your device is fully charged.[2]

Chargers? Really?

With a little Googling I came across an amusing article putting this premise to the test with a power meter.[3] Each charger registered 0 watts. Adding various chargers to a power strip didn’t register more than 0 watts until the 6th charger. The reading with 6 chargers? 0.3 watts. As the article points out, that’s 2.6 kWh/year which at 13 cents/kKh is 34 cents a year. About 6 cents a charger a year.

Not to scoff at saving 6 cents a year from unplugging/plugging a charger every day for a year. But perhaps there are bigger vampires to slay.

OK, What Bigger Vampires to Slay?

It’s said a zillion times on the internet that the Department of Energy reports that homeowners can save anywhere between $100 and $200 each year by unplugging devices not in use.[4] I can’t find this DOE report (if you can please send me the link).[5]

It’s possible that this range attributed to DOE might have its origin in a Natural Resources Defense Council study, which estimated average residential vampire power costs at $165 per year.[6]

The study put power meters on individual electronic devices at a sample 10 homes in California. When you look at the details (Appendix C), you find that the big usages in “inactive” devices are for things like fishpond/aquarium pumps, refrigerators, furnaces, hot water recirculation pumps,[7] GFCI outlets, networking equipment (modems, routers), printers, alarm clocks, irrigation systems, garage door openers and security systems. In other words, not stuff you unplug (assuming you even could). By the way, there were an average of 65 devices per household using vampire power, so one can imagine the hassle of plugging/unplugging these devices on a daily or other routine basis (again, assuming you would or could).

One of the few things you might unplug when not using is set-top boxes. (TVs themselves consume very little power in stand-by mode.)[8] Is someone going to make a habit of unplugging set-top boxes? Waiting for a reboot every time it’s plugged back in? Missing a show you wanted to record because you forgot to plug it back in? I think not.  

In short: Big savings from unplugging vampire power are as much a fantasy as, well, vampires.[9]

Meanwhile Back at the Ranch

Missing from the Delmarva list is an easy way to significantly reduce electric usage: LED lighting. The math is something like 1,105 kwh/year for average residential lighting,[10] times 13 cents/kwh, times 84% for the reduction in electric usage from switching from incandescent to LED lighting, for about $120 per household. While LED lighting has dramatically increased since 2015, it’s dominant in only half of U.S. households, so there’s a long way to go.[11]

And LED lighting pays for itself in equipment savings alone (ignoring the electric bill savings) because it outlasts an equivalent incandescent by maybe 20 times while costing maybe two times as much.

Wrapping Up

There is reason to doubt the value proposition for customers to fund public service advertising by utilities. But where it happens, the least to ask is that utilities promote effectual and hassle-free ways to reduce electric usage instead of ineffectual and hassle-ladened ways.

[5] I emailed the DOE/Berkeley Lab expert on standby power but didn’t get a reply.

[7] It appears these generally come with sensors and/or timers that reduce electric use. https://homeinspectorsecrets.com/hot-water-recirculating-pumps/how-recirculating-pumps-work/

[9] I’m not suggesting that makers of electronic devices shouldn’t reduce vampire power. There’s been progress on that front from voluntary and mandatory standards, and it should continue.

[10] https://www.eia.gov/consumption/residential/data/2015/c&e/pdf/ce5.3a.pdf (data is for 2015, before large penetration of LED lighting).

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ISO-NE: Reliability Still Depends on Mass. LNG Import Terminal

In a new statement released Monday, ISO-NE and many of its gas and electric distributors warned that the region’s near-term grid reliability depends on its access to LNG — and that access to LNG in turn relies on a single facility outside Boston.

The message comes ahead of a summit next week that will bring FERC commissioners and staff to Vermont to discuss the tenuous state of the region’s grid this winter and in the coming years.

The statement published by the RTO says that  weaning New England off its dependence on imported LNG remains its long-term goal, as the region transitions to more renewable generation.

But in the short term, an LNG import facility operated by Constellation Energy in Everett, Mass., is vital to keeping the lights on, it says.

“The region must ensure the continued operation of the Everett LNG Facility to maintain reliable electric and natural gas service for New England consumers,” ISO-NE and the distributors said.

Everett can store the equivalent of 3.4 Bcf of natural gas and has the equipment needed to import, store, transport and re-gasify LNG. It can deliver up to 435 MMcfd to two of the five pipelines used by generators and gas utilities in New England.

The fate of the Everett facility is tied to the attached Mystic Generating Station, which ISO-NE has paid to retain until its retirement in 2024.

In a separate news release, ISO-NE CEO Gordon van Welie called energy adequacy “under-appreciated, poorly understood, but vitally important.”

“By raising awareness of this issue ahead of the upcoming forum, ISO New England and the region’s utilities hope to begin the process of developing a strong, coordinated response with the New England states, NEPOOL and regional stakeholders to assure that energy adequacy is consciously addressed as the region charts a course toward a clean power system,” van Welie said.

The utilities joining ISO-NE in issuing the statement were Avangrid, Eversource Energy, Liberty Utilities, National Grid, Rhode Island Energy and Vermont Electric Co.

Kickstarting Solutions

The aim of the forum next week is to start hashing out solutions to New England’s unique but well documented challenges around gas supply. Aiming to kick off the conversation, ISO-NE put forward a few ideas in its statement Monday.

For one, the grid operator called on the region to “undertake a comprehensive study of both the energy adequacy problem and the potential solutions for addressing the problem.”

ISO-NE shouldered its own responsibility and acknowledged that any changes to its tariff will have to go through NEPOOL and FERC, but it also called on the states to hold up their end of the bargain.

“The New England states have a major role in determining the nature and extent of any regional risk mitigation solution, since they represent the end consumers who will have to pay for the insurance, and further, control the siting and permitting of the necessary infrastructure,” the statement says.

The RTO also put new weight behind the idea of an energy reserve, which was raised recently by the New England states in a request to the Biden administration. (See New England Governors Ask Feds for Help with Winter Reliability.)

“An energy reserve would cover unusual events, including combinations of major contingencies or extreme weather or both,” ISO-NE said, likening it to regionwide insurance.

The grid operator said a reserve could come in a few different forms: state-regulated cost-of-service infrastructure investments coupled with contracting for the energy; FERC-regulated cost-of-service rates for recovering infrastructure investments and forward energy supply chain arrangements; or FERC-regulated wholesale electric market tariffs to incentivize investment.

“At this stage, given the region’s experience over the past two decades, the region needs to determine how much insurance to buy and which options, or combinations of options, will be the most effective and efficient,” the grid operator said.

All in the Same Room

The forum next week — an all-day affair in Burlington, Vt., on Thursday — will feature nearly 30 panelists from the states, FERC, ISO-NE, distribution and pipelines companies, and more.

According to FERC, it’s intended to “achieve greater consensus or agreement among stakeholders in defining the electric and natural gas system challenges in New England and identify what, if any, steps are needed to better understand those challenges before identifying solutions.”

ISO-NE and the states, in particular, have been lobbing barbs back and forth for years over who holds responsibility for solving the problems facing the region.

Even in the unlikely event of a breakthrough or consensus on Thursday, it’s likely too late to make changes that could help steady the grid this winter: ISO-NE has already said it won’t take steps to stockpile fuel, and that rolling blackouts could be on the horizon if the region sees an extended period of extreme cold. (See ISO-NE Says No Extra Winter Programs Make Sense this Year.)

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NJ BPU Denies Deadline Extensions for Solar Project Incentives

New Jersey’s Board of Public Utilities (BPU) earlier this month denied requests by 15 solar developers seeking to extend the completion deadlines for 37 projects.

While the board at its regular meeting Aug. 17 also granted extensions for hundreds of other projects, members expressed reluctance over the denials, as the state faces its own deadline crunch on its renewable energy goals and developers face financial uncertainty and supply chain challenges.

The series of decisions affect participants in the state’s temporary Transition Incentive (TI) program. Now closed to new projects, it provided incentives of between $91.20 and $152/MWh. Projects that aren’t finished by the deadline — initially a year from the project approval — and do not receive an extension would lose the incentive and have to apply to the less lucrative program that succeeded TI.

The BPU said the 15 developers had failed to show sufficient evidence that delays to their projects’ construction were caused by events beyond their control. At the same time, it approved a six-month deadline extension for hundreds of public entities, including schools, universities and municipalities. And the board granted a deadline extension of up to a year for 30 projects planned on a landfill, brownfield or area of historic fill.

The board also approved a six-month extension for four projects approved for TI benefits as part of the state’s community solar program, but it denied an extension to five other projects in the program, saying they were too far from completion.

Providing Certainty

Outlining the decisions at the meeting, Scott Hunter, manager of the BPU’s Office of Clean Energy, said they were aimed at “providing clarity, certainty and support” for solar projects while limiting the cost to ratepayers of extending the deadline and allowing projects that miss their deadline to remain in a higher incentive program.

BPU President Joseph Fiordaliso told the board that the votes demonstrate “the desire of this board to work with the solar industry” while reducing the burden on ratepayers.

The BPU created the TI program to help reshape the state’s incentive programs away from the Solar Renewable Energy Certificate (SREC) Program, which dispensed incentives of about $250/MWh for more than a decade until it closed in April 2020. With incentives about half the size of the SRECs, TI followed in May 2020 but was closed soon after the BPU in July 2022 approved the permanent Successor Solar Incentive Program, with incentives between $70 and $100/MWh.

The shift stemmed from a 2018 state law that directed the BPU to close the SREC program once it reached 5.1% of the power sold. That happened  on April 30, 2020. (See Solar Subsidy Program Ending in New Jersey.)

BPU data for the first half of 2022 show the state is on track to meet a 2025 goal of 5.2 GW of capacity set out in the state Energy Master Plan but needs a dramatic increase in annual capacity installed to meet goals of 12.2 GW in 2030 and 17.2 GW in 2035. (See NJ Faces Challenges as Solar Sector Hits 4 GW.)

Mixed Bag

Fiordaliso said that the state has cultivated and supported the solar industry for 20 years, and the decision to grant only certain extensions reflected that strategy of reducing financial support.

“The industry knew that eventually they were going to get closer to standing on their own two feet,” he said. “We did nothing in secret. We did it in conjunction with the stakeholders. And I think the state of New Jersey has thrived. I think the developers have thrived. And if we continue to work together, we will continue to maintain the solar industry as a major industry here in the state of New Jersey.”

The board voted 4-0 on the extensions, with one abstention. Commissioner Zenon Christodoulou, who joined the board on Aug. 15, didn’t vote in the meeting because he felt that he needed more time to study the issues.

Commissioner Bob Gordon said that any government support for an industry “needs to balance the goals of advancing the new industry against the cost impact.”

“At some point, you need to cut back on those incentives,” he said. “When that industry grows up, if you don’t do that, the risk is the ratepayers subsidize inefficiency. And that’s not what we want to do.”

Scott Elias, manager of Mid-Atlantic state affairs for the Solar Energy Industries Association (SEIA), called the board’s votes a “mixed bag for the industry.”

“It is our opinion that an orderly transition from the Transition Incentive program to Solar Successor Incentive Program ought to recognize that industry is not immune to COVID-19 or global economic trends that leave customers navigating a supply chain riddled with bottlenecks and delays,” he said.

“It’s great that the BPU made limited extensions for some community solar projects and projects serving public entities,” he said. “But markets cannot efficiently operate when power purchase agreements need to be retroactively renegotiated because projects literally can’t be built, interconnected and operating in a narrow 12-month timeline due to unavoidable delays caused by the COVID-19 pandemic.”

Elias also said the extensions for the 30 brownfield projects “will not address the PJM interconnection delays associated with every [brownfield] project that followed the rules and applied before the closure of the TI program in August of 2021.”

“Put simply, the order insufficiently addresses all of the concerns that led to the introduction and passage of A4089,” a bill that would automatically extend the completion date for brownfield solar projects that cannot be completed because of interconnection problems caused by PJM or a utility. The General Assembly passed it unanimously in June, but the Senate has not acted on it. Another trade group, NJ Utility Scale Solar, has backed the legislation and called for a “blanket” deadline extension for TI projects.

Deadline Extension Guidelines

BPU officials gave varying reasons for the extension denials or approvals.

The rejected 37 projects were “not mature enough to meet TI deadlines,” the BPU said in its order. The projects all filed their application shortly before the TI program was closed and cited supply chain difficulties as preventing completion. But developers “knew, or should have known, that they were not going to be able to complete their projects within the time frames enumerated in the TI rules,” the BPU said.

The board noted that in June, it granted a request by ESNJ-Key-Gibbstown to extend the deadline on a 1.38-MW carport solar project in Gibbstown. The board had already granted the project two deadline extensions, and the developer — faced with an April 30 deadline by which to show project completion — sought an additional extension of three months.

The developer argued that it had completed the project but could not interconnect it because Atlantic City Electric had not performed the necessary transmission upgrades.

In granting Gibbstown the extension, the BPU laid out general guidelines on when it would be appropriate to override TI project rules. One of them requires the project to show that the project was electrically and mechanical complete before the deadline expired and had received the necessary final inspections. They also require that the developer show that the utility had committed in advance to completing any upgrades needed to interconnect the project by the deadline but, “despite the developer’s best efforts, the estimated upgrade completion date was unilaterally extended by the” utility.

The 37 projects denied an extension did not demonstrate those conditions, the BPU said.

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FERC Approves Changes to ISO-NE DER Interconnection Process

FERC last week accepted ISO-NE’s proposed changes to its process for interconnecting distributed energy resources, finding them just and reasonable with some clarifications (ER22-2226).

Previously, some DERs had used the ISO-NE interconnection process, while others used state interconnection processes, a disconnect that the grid operator said “results in multiple coordination problems and inefficiencies that in some cases result in adverse outcomes for DER developers.”

ISO-NE proposed that all new DERs proceed through the applicable state processes to ease the uncertainty. (See ISO-NE Sends New DER Interconnection Proposal to FERC.)

In an order on Friday, FERC agreed that the change makes sense.

“We find that ISO-NE’s proposal to exclude DERs from its interconnection procedures is just and reasonable because it would promote certainty in ISO-NE’s interconnection process and reduce a significant burden on ISO-NE,” the commission wrote.

FERC also clarified that “the commission’s jurisdiction over wholesale sales from DERs and their participation in the wholesale markets are not impacted by the change.”

The Solar Energy Industries Association, Advanced Energy Economy and ENGIE North America had all backed the changes, saying they would help resolve unique concerns in New England because of the growth of DERs in the region.

After FERC’s approval, the tariff changes went into effect Sunday.

ISO-NE’s proposal concerned individual DERs; as such, it is separate from its compliance with FERC Order 2222, which deals with DER aggregations. In concluding its order, the commission noted that, as it had in Order 2222, it “may revisit this independent entity variation in the future should [it] discover abuses of the distribution interconnection process or the rise of unnecessary barriers to the participation of distributed energy resources in RTO/ISO markets.”

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Texas RE Board of Directors Briefs: Aug. 24, 2022

NERC Cold Weather Standard Development Coming to Close

AUSTIN, Texas — A member of the NERC team drafting the industry’s new cold weather standard told the Texas Reliability Entity Board of Directors last week that the standard is on track to be approved in October.

Occidental Power Services’ Venona Greaff, also a member of Texas RE’s Member Representatives Committee, told Texas RE staff and its directors Wednesday that the standard has been posted for a second round of industry comments. The posting expires Sept. 1.

“There was a lot of effort put in by members of the drafting team, but also by industry,” Greaff told ERO Insider, speaking for the team. Stakeholders “took their first pass at it and felt like they at least had a good starting point. Industry provided a lot of valuable feedback, and the drafting team did everything they could to incorporate that feedback … to get to where we’re at now.”

The new standard for extreme cold-weather preparedness and operations (EOP-012-1) is part of Project 2021-07 (Extreme Cold Weather Grid Operations, Preparedness, and Coordination), which NERC started last year in response to the mass outages caused by the February 2021 winter storm. The standard includes four new requirements and strengthens several existing requirements that address reliability-related findings by NERC, FERC and regional entity staff.

The standard will require generator owners to implement freeze-protection measures so the units can operate for at least 12 continuous hours in extreme cold weather, defined as the temperature equal to the lowest 0.2 percentile of the hourly temperatures measured in December, January and February from January 2000 to present day.

Generator owners will also be responsible for ensuring their units add new or modify existing freeze-protection measures as needed to be able to operate for at least an hour during extreme cold-weather temperatures. Those units not able to meet the one-hour standard will be required to develop a corrective action plan (CAP) for modifications to a cold-weather preparedness plan.

“We’re hopeful that it is something that industry is satisfied with and can get on board with and improve,” Greaff said.

The cold-weather standard will be effective with the 2023 winter season.

NERC’s Board of Trustees will hold a special meeting in October to vote on the standard. It will then go to FERC for final approval.

New Braunfels Chief Discusses Challenges

In a keynote presentation, New Braunfels Utilities (NPU) CEO Ian Taylor said that while the ongoing transformation of the electric grid is “absolutely exciting,” it has also created challenges for utilities across Texas.

“Even [with] foundational activities like procurement and budgeting, what we’ve done in the past is just not adequate anymore for what we’re being called to do,” Taylor said. “We’re adding tools [and] expertise; we’re redefining and creating processes to be able to handle the type of work that we’re [doing]; and then we’re also having to recreate our workforce. …

“You’ve got to recalibrate folks to think critically and analytically in ways they’ve never done before. That takes some work; it doesn’t just come naturally.”

One of the topics that Taylor touched on was the effect of last February’s winter storm, which resulted in more than 23 GW of manual firm load shed, mostly in Texas. NBU itself experienced a number of equipment failures during the crisis, including 21 transformer failures and three downed wires, but it reported no transmission issues.

While the storm was “a significant emotional event” for NBU — a publicly owned provider of water, sewer and electric services in Texas’ Hill Country — Taylor was proud that the utility had no outages on its system after the end of rotating outages and only one tree-related outage during the event. In addition, the crisis was a chance to test NBU’s procedures and see where they came up short when confronted with a real disaster.

“We’ve always had an emergency management plan, but this gave us an opportunity to really go in” and revise the work the utility had done before, Taylor said.

“We got some minimum inventory levels that we didn’t really have formalized before, and lots and lots of lessons learned and coordination with local government entities that came out of that,” he continued.

Fall Workshops Scheduled

The Texas RE has scheduled a pair of workshops this fall focused on grid resilience, security and reliability.

A two-day Extreme Events Resiliency Workshop will be held Sept. 20-21 at a yet-to-be-determined location. Staff will moderate a series of panel discussions with industry experts on planning for and maintaining resilience during both natural and manmade extreme events.

ERCOT staff and state regulators overseeing the electric and gas industries will also be on hand to update attendees on their winterization activities.

Texas RE will host a Standards, Security and Reliability Workshop on Oct. 27 in its Conference Center. Virtual attendance will also be offered.

In other actions, the board’s Nominating Committee put up incumbent independent Directors Crystal Ashby and Jeff Corbett for additional three-year terms, effective January 2023.

Texas RE’s First In-person Meetings

The board and MRC meetings marked the Texas RE’s first in-person meetings since February 2020, just before the COVID pandemic began, and the first in its new office space located conveniently in the same complex as ERCOT’s new headquarters building.

“Every time I think about the date, I [say], ‘It can’t be over two years.’ But it has been,” board Chair Milton Lee said. “This meeting in person has been fantastic. I’m grateful the building was completed. Let’s hope we can continue to meet person-to-person without going back to virtual.”

“We’re still working on the technology in this room,” Texas RE CEO Jim Albright said, referencing several audio problems. “By 2023, we hope we’ll be full bore in how we’re going to have this meeting. You’re kind of the guinea pigs today.”

The board last year approved the entity’s request for a 20% budget increase to $17.2 million to help cover additional staff and relocation costs for the new space. Staff said it will save about $1.3 million over a 10-year period with the move. (See Texas RE Asks for 20% Budget Increase.)

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SACE Urges FERC Inquiry into Proposed TVA Gas Plant

The Southern Alliance for Clean Energy (SACE) has protested with FERC that the Tennessee Valley Authority’s justification behind a new gas plant’s construction is faulty, urging the commission to conduct its own assessment into the resource’s need.

TVA has proposed a natural gas plant and a 32-mile pipeline to replace its coal-fired Cumberland Fossil Plant northwest of Nashville. The alliance said the federal agency would be better served with a blend of large-scale and distributed solar, wind and storage resources and energy efficiency measures.

SACE’s protest was registered in a docket related to Tennessee Gas Pipeline Co.’s request for FERC permission to build the gas pipeline. The alliance was among several public-interest groups that urged TVA in June to rethink its plans after the agency filed its environmental impact statement (CP22-493). (See Nonprofits Urge TVA to Reconsider Gas-fired Options.)

SACE repeated its position that the draft EIS isn’t a reliable document and lacks a transparent analysis to support it. The alliance said FERC should assess other alternatives. It said the draft clings to an outdated and rosy natural gas price forecast and said it is based on TVA’s 2019 integrated resource plan, which used assumptions made from 2016 to 2018 and predates President Joe Biden’s executive order that calls for net-zero carbon emissions in the electric sector by 2035.

“Were TVA to build a new carbon-emitting gas CC at Cumberland by 2026, with no plans for capturing the carbon, it will immediately become a stranded asset in less than a decade and thus add to the utility’s costs that must be borne by the 10 million people it serves,” SACE said.

It also said the federal agency didn’t consider the possibility of energy efficiency programs offsetting some demand or importing wind power into its territory.

“Since TVA is currently lagging the Southeast in energy efficiency savings, a region that lags the country in energy efficiency savings, and the National Renewable Energy Laboratory estimates there is substantial energy efficiency potential in just Tennessee alone, it is absolutely reasonable to assume that energy efficiency would be a cost-effective addition to a clean energy portfolio replacement,” SACE argued.

The alliance also suggested that TVA executives may have a conflict of interest, noting they receive millions in bonuses tied to the availability of coal and gas plants but don’t have any incentives attached to expanding renewable energy or energy efficiency.

SACE said there is no evidence that TVA took any steps to meaningfully evaluate other Cumberland replacement plans.

“These actions could have included issuing a request for proposals for renewable energy and energy storage resources, staffing up its interconnection study department to prepare to interconnect renewable energy projects faster, identify and begin planning transmission projects to ease the integration of renewable energy projects and beginning to set up energy efficiency programs and other demand-side measures,” SACE said. “TVA’s actions to date make it very clear that it always intended for the gas [combined cycle] option to be its preferred option regardless of the environmental review process, and that brings the merit of its environmental review into question.”

The Sierra Club and Appalachian Voices also filed protests in the docket. They said the Tennessee Gas Pipeline “can offer no reliable evidence that its only customer, TVA, will ever be able to move forward with its plans.”

“The proposed power plant would emit millions of tons of greenhouse gases each year, rendering it incompatible with the President’s executive orders on climate change, dependent on a volatile and increasingly expensive fuel, and more costly than an available suite of clean energy resources,” the environmental advocates said.

The Sierra Club and Appalachian Voices also urged FERC to “independently evaluate the need” for Cumberland City and the pipeline and consider “clean energy alternatives that could replace both at lower cost to ratepayers.” It said the commission’s examination is needed because TVA lacks meaningful oversight and competition.

TVA maintains that it hasn’t made a final determination regarding its natural gas plant plans.

“TVA has not made any decisions about the future of that plant nor replacement options, pending completion of the [National Environmental Policy Act] process later this year,” spokesperson Ashton Davies said in a statement to RTO Insider.

TVA stressed that it is not involved with the construction of the pipeline or its permitting and regulatory process. Davies said the utility would merely be a customer of the pipeline should it elect to construct a gas-fired plant.

“TVA is supportive of the project as it would be a likely source for natural gas, should TVA choose that option to replace capacity at Cumberland Fossil Plant,” Davis said.

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SPP Briefs: Week of Aug. 22, 2022

Platte River Joins Western Utilities Evaluating RTO Membership

SPP on Thursday welcomed Colorado utility Platte River Power Authority as the latest Western utility to provide a notice of intent to evaluate participation in the grid operator’s planned RTO West.

Platte River is the eighth Western entity that has publicly committed to exploring SPP’s RTO expansion. The utility has already announced plans to join the RTO’s Western Energy Imbalance Service (WEIS) market next April.

“We look forward to joining the WEIS next year and SPP’s RTO in 2025,” Platte River COO Melie Vincent said.

SPP administers the WEIS market on a contract basis and provides participants with a suite of services including market administration, transmission planning, reliability coordination and more. It says WEIS participants that become full RTO members can expect to receive similar savings and benefits as its Eastern Interconnection members. According to the grid operator, those members saved $2.696 billion last year, a benefit-to-cost ratio of 18-to-1 given $149 million in net revenue requirement costs.

The RTO has set a March 2023 target for Western utilities to indicate their intent to participate in its initial expansion into the interconnection. SPP expects to extend its RTO into the West in March 2024.

“We are pleased that Platte River will be joining the WEIS market next year and is evaluating the cost and benefits of full RTO membership,” said Bruce Rew, SPP’s senior vice president of operations. “Our continued collaboration will enable us to help them reliably and economically serve their communities while meeting their clean energy goals.”

Basin Electric Power Cooperative, Colorado Springs Utilities, Deseret Power Electric Cooperative, Municipal Energy Agency of Nebraska, Tri-State Generation and Transmission Association, Western Area Power Administration and Wyoming Municipal Power Agency are the other entities that have already expressed interest in the RTO.

MMU Releases WEIS Spring Report

SPP’s Marketing Monitoring Unit (MMU) last week released its WEIS quarterly State of the Market report for the spring period, which covers March through May 2022.

The MMU said it believes that the WEIS “functioned as expected” during its second spring quarter of operations. It said the market continues to struggle with ramp availability and short-term system flexibility despite an abundance of online capacity but noted those issues have persisted since it began operations in February 2021.

The Monitor said many dispatchable resources are offered with minimal available dispatchable and/or rampable capacity. “Market participants are also reluctant to offer additional resources due to risks associated with recovering costs when prices drop,” the MMU said.

It noted SPP has begun conversations with market participants to discuss offered rampable capacity and encourages more capacity to be offered to increase market efficiency. “The MMU supports the incremental improvements to the market enacted during this period and continues to recommend further enhancements,” it said.

Average load prices during the period were consistent with the year prior at $15.71/MWh and $19.48/MWh for March and April, respectively, and increasing to $26.85/MWh in May. Coal remained the predominate fuel source ahead of hydropower, accounting for 66% of the market’s generation in March before dropping to 59% by May.

SPP administers the market for 12 utilities, centrally dispatching energy from participating regional resources every five minutes.

RTO, AECI to Target Efficient Joint Solutions

SPP staff told stakeholders last week that they will be taking additional steps this year as they work across the seam with a neighboring cooperative to identify interregional projects.

Neil Robertson, the RTO’s coordinator of system planning, said during a joint stakeholder planning meeting with Associated Electric Cooperative Inc. (AECI) on Wednesday that the staffs are going to work with local transmission owners to find the best solutions for their needs.

“In years past, I felt soliciting for transmission solutions for all the needs was not efficient. As we refined [the solutions], we discovered we might not have a true jointly funded opportunity,” Robertson said.

SPP has already analyzed updated models and contingency files provided by AECI and found more than 90 thermal and voltage needs. He promised a review of proposed solutions and to discuss potential joint projects when staff next meet with AECI and stakeholders later this year.

AECI Joint Study Needs Aug 22 (SPP) Content.jpgThermal, voltage needs on the SPP-AECI seam | SPP

 

“We got some good project solutions, but when we’ve looked at that through a joint system plan with AECI, the benefits went to one or the other,” Robertson said. “In this refinement, we’ll do some additional due diligence to ensure that the opportunities that move forward clearly demonstrate a shared reliability need and shared benefits. I think this will increase overall efficiencies.”

RFP out for NM Project

SPP has issued a request for proposals in soliciting bids for the 345-kV Crossroads-Hobbs-Roadrunner project in eastern New Mexico.

Companies soliciting proposals will need to include a $50,000 deposit for each response. Each deposit will be held in a segregated interest-bearing account in the respondent’s name.

Notices of intent to submit an RFP response are due Nov. 23. The final deadline for responses and deposits is Feb. 21, 2023. A pre-response open meeting will be held Sept. 23 for qualified RFP participants to ask questions and get feedback.

The project, proposed by Southwestern Public Service, was approved in July as part of the 2021 Integrated Transmission Plan. The project was re-evaluated after load-projection errors were discovered in the original solution. (See “Members Approve SPS Tx Project over Staff’s Recommendation,” SPP Board of Directors/Members Committee Briefs: July 26, 2022.)

Staff said in July the project would likely qualify as competitive under FERC Order 1000. The grid operator has already awarded four such projects.

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PJM Markets and Reliability Committee Briefs: Aug. 24, 2022

Discussions Continue on Market Seller Offer Cap

VALLEY FORGE, Pa. — Load interests continued to oppose PJM’s proposal to change the market seller offer cap (MSOC), a month after it failed to meet the two-thirds endorsement threshold at the July 27 Markets and Reliability Committee meeting.

The proposal, which would ensure sellers are always able to represent the cost of their Capacity Performance (CP) risk when offering into the Base Residual Auction, had won only 60.4% support, as load sector stakeholders expressed concern over its impact on capacity prices. (See Change to PJM Market Seller Offer Cap Falls Short.)

The rule change would set the MSOC at the greater of the CP quantifiable risk (CPQR) or net avoidable-cost rate (ACR) inclusive of CPQR. PJM said it would address circumstances in which a unit with a positive CPQR value has that cost offset by an otherwise negative net ACR, which could result in a $0 offer cap. PJM had hoped to win stakeholder and FERC approval for the change effective with the 2024/25 capacity auction in December.

Load interests remained cool to the idea at the MRC on Wednesday.

Gregory Carmean, executive director of the Organization of PJM States Inc. (OPSI), asked PJM’s Pat Bruno why it was in buyers’ interests to “pay upfront the default costs of a supplier.”

“We think it’s in consumers’ interests to achieve competitive outcomes in the auction results,” Bruno responded. That result, he said, is “clearing the cheapest set of resources including the risk of nonperformance.”

Susan Bruce, representing the PJM Industrial Customers Coalition, suggested more work was needed before considering the proposal. “Are we ready for prime time with this vote?” she asked.

Independent Market Monitor Joe Bowring said PJM’s proposal would displace the Monitor’s role in setting the offer cap and fails to adequately define CPQR.

“We do not agree that what’s being proposed is a competitive outcome, or that it’s a narrow change,” he said. “You simply can’t have an unlimited adder that’s not defined in the tariff.”

Bowring said not using net energy revenues as an offset to CPQR breaks the “essential link” between the energy market and the capacity market, which generally means lower capacity prices when energy market prices are high. Because PJM has not defined how it would calculate the CPQR or the asserted opportunity cost, the RTO cannot say that the impact would be small, Bowring said.

Carl Johnson, representing the PJM Public Power Coalition, said his members agree with Bruce’s and Bowring’s concerns.

“I’ve become convinced we cannot have this discussion separate from the holistic” discussions at the Resource Adequacy Senior Task Force, he said. The proposal “is such an open door to market power that I don’t see how PJM could effectively mitigate it.”

However, Johnson said his members “do want to represent CPQR in their offers, so they wouldn’t go as far as [Bowring] recommended.”

Jason Barker of Constellation Energy said PJM’s proposal is “consistent with real-world economic decisions” that generation owners are making.

“PJM’s proposal is welcome; it’s ready; and it solves a very distinct problem that sellers encounter time and again,” he said. “A compulsory capacity commitment is not risk-free.”

Manuel Esquivel of Enel North America also expressed support, saying the status quo is not just and reasonable.

Tom Hoatson of LS Power also called for change to the offer cap, saying current rules result in “over-mitigating.” He said his company supports the PJM proposal with several revisions, including that the CPQR should be based on the market seller’s view of the risk of taking on a capacity obligation.

“This risk is viewed differently by different market sellers, and the market seller’s view of this risk is commercially sensitive,” he said. “One size doesn’t fit all, and the process needs to reflect that.”

LS Power also would change the deadline for requesting an exception to the must-offer requirement, making it at least five days after receipt of the final unit-specific MSOC value from PJM and the IMM. The current deadline is the same day as when the final MSOC is issued.

Hoatson also said all models, data and methodologies that the Monitor and PJM use to make their determinations should be made available to the market seller before their decisions are made.

Under the current rules, “it’s a black box,” Hoatson said. “We don’t know how the numbers were arrived at, so we can’t debate them with the IMM and PJM. Perhaps we’re wrong. Perhaps the other side is wrong. We don’t know.”

GreenHat Payments Expected by January

PJM Assistant General Counsel Mark Stanisz told members that the RTO should receive $1.375 million in disgorgements from the principals of the defunct GreenHat Energy by the end of January.

Under settlements approved by FERC on Aug. 19, two of GreenHat’s founders and the estate of the third agreed to pay the disgorgements. The principals also consented to the entry of a $179.6 million judgment against the company, reflecting the losses suffered by PJM market participants when GreenHat defaulted on its obligations in the financial transmission rights market in 2018. (See FERC OKs GreenHat Settlements.)

But PJM has no hope of recovering any of the nearly $180 million, Stanisz said. GreenHat “has no funds and no assets,” he said.

FERC ordered PJM to distribute the disgorged monies “in a reasonable manner” approved by the commission’s Office of Enforcement. The RTO said it will likely do so in a single distribution.

In response to a request from Constellation, PJM said it would advise market participants where they will see the disbursements in their billing statements.

Revised Bankruptcy Rules

PJM proposed changes to its credit policies to provide greater protections against bankruptcies by market participants, the RTO’s latest response to the GreenHat default.

The revisions would clarify that PJM has a first priority security interest in market participants’ cash deposits.

PJM would also require that a party filing for bankruptcy immediately address the RTO’s rights with a “first day” motion ensuring the full repayment of pre-petition obligations and the continuation of post-petition obligations.

The new language aims to demonstrate to bankruptcy courts that PJM has interests that are set apart from “garden variety” creditors, Assistant General Counsel Eric Scherling told the MRC. Though there are limitations on PJM’s ability to compel action from parties that have filed for bankruptcy, the revisions are aimed at making the proceedings go more smoothly to mitigate potential losses from delays.

“PJM is different, and we want to basically do whatever we can … to lay the groundwork as to why PJM is different,” Scherling said.

Tariff language would be changed to clarify that FTR transactions “are entitled to the special protections given to ‘forward contracts,’ ‘swap agreements’ and ‘master netting agreements’” under the U.S. Bankruptcy Code, including exceptions from automatic stays and allowing for immediate termination or liquidation.

The revisions were endorsed by the Risk Management Committee in July after meeting to discuss the issue six times. The proposal is expected to go before the MRC for approval next month.

FERC already approved revisions to PJM’s credit policy for FTR transactions in September 2018, setting a minimum credit requirement for FTRs equal to 10 cents/MWh (ER18-2090).

FTR Manual Changes Endorsed

The MRC endorsed revisions to Manual 6: Financial Transmission Rights as part of a periodic review and changes to conform with tariff revisions intended to increase the transparency and efficiency of the RTO’s auction revenue rights and FTR markets. The changes were approved by FERC in March (ER22-797). (See FERC Accepts PJM ARR/FTR Market Changes.)

Variable Environmental Costs and Credits Rules OK’d

Members approved an update to rules governing variable environmental charges and credits and their inclusion in cost-based energy offers. Generation units receiving production tax credits or renewable energy credits must reflect them in their fuel-cost policies when submitting non-zero cost-based offers into the energy market. The changes will include revisions to Manual 15: Cost Development Guidelines and Operating Agreement Schedule 2. (See “Variable Environmental Costs and Credits,” PJM MIC Briefs: May 11, 2022.)

Johnson thanked PJM for addressing Old Dominion Electric Cooperative’s concerns regarding differentiating fuel costs from emissions costs.

The update will be brought to a Members Committee vote in September.