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November 6, 2024

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FERC Approves SPP Cost-allocation Waiver Plan

FERC has approved an SPP proposal that establishes a way for “byway” transmission projects to be allocated across the RTO’s entire footprint on a case-by-case basis.

Under current rules, SPP allocates one-third of the cost of byway projects — lines rated at 100 to 300 kV — to the RTO’s full footprint, with customers in the transmission pricing zone where the project is built being allocated the rest. “Highway” projects — those larger than 300 kV — are allocated RTO-wide.

The new process allows entities to seek exceptions to the RTO’s cost-allocation process for byway facilities, addressing a growing issue for ratepayers in transmission zones where most of the power being generated is exported to other areas (ER22-1846).

In a 3-2 decision issued Oct. 28, the commission found that the proposal will help ensure that SPP’s “byway” facility costs are allocated roughly commensurate with estimated benefits, consistent with FERC’s cost-causation principle. The order is effective Aug. 1, 2022.

Commissioners James Danly and Mark Christie dissented from the order, saying it forces some states to pay for other states’ renewable energy policies. Kansas was the only one of the 14 states in SPP’s footprint to support the order at FERC.

Al Tamimi, vice president of transmission policy and planning for Sunflower Electric Power, said the order addresses the changes necessary to align costs and benefits for local zones with renewable energy that exceeds the zones’ peak loads and is exported to other zones in SPP.

“In renewable-rich zones, the function of the byway transmission facilities has changed from mainly serving local loads to now carrying and exporting regional flows … where the byway facilities function as a regional flow carrier,” Tamimi told RTO Insider. “Renewable-rich areas like Sunflower Electric have experienced increased costs required to build transmission infrastructure that export substantial energy to other areas of the SPP region. The majority of the transmission costs for byway transmission facilities have been shouldered by local ratepayers versus those benefiting from the energy exports.”

Tamimi has been involved in finding relief for wind-rich zones since 2017. The Holistic Integrated Tariff Team in 2019 recommended evaluation of a narrow process through which specific projects between 100 and 300 kV could be fully allocated regionally. Transmission owners largely opposed the proposal as it wound its way through the stakeholder process, saying it would shift byway cost responsibility from wind-rich areas to others.

SPP singled out Sunflower in its request to FERC. It said the Kansas utility’s pricing zone has 3,100 MW of wind but only a 900-MW peak load.

SPP’s first attempt to gain approval was rejected last year by FERC over concerns the proposal granted the RTO’s Board of Directors too much discretion in allocating costs and did not include clear standards for making decisions. (See FERC Rejects SPP’s Cost-allocation Waiver Proposal.)

The majority in the Oct. 28 decision said Danly failed to identify any evidence to support his conclusion that SPP’s proposal is “designed to facilitate the shifting of some states’ public policy costs onto other states.” The commissioners noted that 11 of SPP’s 14 states do not have active renewable energy standards and that a majority of those that do not (seven out of eight) voted in favor of the measure at the Regional State Committee meeting.

“Such robust support for the proposal, including among states without public policies, strongly undercuts [Danly’s] claims about improper cost shifts,” the majority said. “What matters here is that SPP’s proposal establishes regional cost sharing, consistent with the cost-causation principle, where the relevant infrastructure provides significant benefits to the entire region.”

SPP Responds to Self-funding Comments

SPP on Monday responded to a protest by a group of clean energy advocates that argues the RTO’s proposal to create a standard pathway for TOs to build and profit from network upgrades necessary to bring generators online is “patently deficient” and should be rejected outright (ER22-2968).

The grid operator told FERC that it made clear in its original request that it was not proposing tariff revisions to provide for the TO self-funding option, given that this option already exists in its pro forma generator interconnection agreement. Instead, staff said, the revisions were providing details for implementing the TOs’ right to elect self-funding, including a pro forma facilities service agreement that would promote administrative efficiency and predictability for TOs and interconnection customers.

TOs would be able to recover the self-funding network upgrade costs and a return on the investment from the interconnection customer. FERC approved a similar request by MISO in 2020 (ER20-359).

The American Clean Power Association, Advanced Power Alliance, Solar Energy Industries Association, Natural Resources Defense Council and Sustainable FERC Project filed the protest in October, urging the commission to reject SPP’s request.

They said the RTO’s proposal is “wholly unsupported” and would be unjust and unreasonable if accepted. SPP has the burden under Section 205 of the Federal Power Act to demonstrate that the proposed change is just and reasonable, they said, noting that FERC can reject a filing that “patently fails to substantially comply with the applicable requirements” of its regulations.

“SPP did not submit any information to support the proposed tariff change,” the coalition said, claiming the tariff filing is “devoid” of supporting information. “The entire filing consists of a 17-page transmittal letter and the proposed revised tariff records. SPP failed to include any testimony or supporting affidavits and has failed to meet its burden under Section 205.”

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PJM PC/TEAC Briefs: Nov. 1, 2022

PJM Presents Changes to CIR for ELCC Resources Proposal

VALLEY FORGE, Pa. — The PJM Planning Committee continued fine-tuning the five remaining packages addressing the level of capacity interconnection rights (CIRs) assigned to effective load-carrying capability (ELCC) resources on Nov. 1.

PJM’s Jonathan Kern presented changes to the RTO’s Package I to expand eligibility for transitionary headroom studies to include all resources, rather than solely ELCC generators. The studies will investigate permitting facilities to receive a higher level of temporary/annual CIRs and include energy up to this higher level when accrediting the amount of capacity they can offer for the Base Residual Auction. The increased CIRs will be based on existing headroom in the transmission system at the time the studies are conducted. Under the proposal, they would be able to do so until all transitionary interconnection study queues have been completed, in addition to the first queue under the new system. (See Stakeholders Challenge PJM in Capacity Accreditation Talks.)

A study of transmission headroom would be conducted each year before the BRA to determine how much is available and how to allocate it. Stakeholders questioned if alternatives have been considered for how to distribute that headroom among generators if requests for CIRs exceed the headroom available, such as prioritizing those units that would provide the most value to load.

Kern said the PJM proposal would prorate the headroom based on factors such as a facility’s power flow. If a study finds a generator is close to an electrical overload, it will likely be scaled down more than other units in that area. Kern indicated PJM was considering a final approach to this type of adjustment.

Expanding the use of headroom to all resources was a compromise with generation owners who felt limiting the studies to just ELCC resources was discriminatory. Tom Hoatson of LS Power said expanding the headroom studies met one of his company’s concerns with the PJM package. But he said the overriding issue is ensuring that the solution chosen is effective for next year’s June auction. He said multiple auctions have been held without the issue being resolved.

“We’re getting close to having a resolution; we’re getting close to putting this in place,” he said.

Economist Roy Shanker said it’s important that any issues that come up over the coming months don’t create delays that could prevent the new rules from being ready for the auction.

“It’s already been three auctions where what we consider an incorrect accreditation has taken place,” he said.

Ken Foladare of Tangibl said it’s likely many stakeholders will remain interested in PJM’s Package D, which he pushed to remain under consideration until the PC takes an endorsement vote. Three additional packages also remain: Package E from LS Power, Package F from Eolian and Package G from E-Cubed Policy Associates. (See “Poll Opened to Gather Support for Packages on CIR for ELCC Resources,” PJM PC/TEAC Briefs: Oct. 4, 2022.)

$50M+ in Projects Reviewed by TEAC

PJM reviewed several baseline reliability projects totaling more than $40 million as part of its reliability analysis update:

  • Purchasing a spare VAR 345-kV reactor for Penelec’s 345-kV Mainesburg substation at a $6.44 million price tag.
  • Installing two new 500-kV breakers on the existing open SVC string, which would be relocated into a new bay location at the 500-kV Black Oak substation near Rawlings, Md. The APS proposal also calls for installing a 500-kV breaker on a 500/138-kV transformer and upgrading relaying in the substation. The work is expected to cost $17.37 million with a June 1, 2027, in-service date.
  • Baltimore Gas and Electric and PECO Energy recommended replacing and upgrading equipment along the companies’ 500-kV Peach Bottom-Conastone circuit, which is overloaded for multiple contingencies. The recommended solution for BGE’s side of the work includes upgrading two breaker bushings on a Conastone substation, while the PECO work would involve replacing 4 meters and bus work inside the Peach Bottom substation. The total cost of the work is expected to fall at $5.8 million with an in-service date of Dec. 1, 2027.
  • PPL has identified that a stuck breaker contingency would result in the 500/230-kV Lackawanna transformer No. 3 being overloaded. The solution recommended is to re-terminate transformers Nos. 3 and 4 on the 230-kV side to remove them from the buses and into dedicated bay positions. The work is expected to cost $10.7 million with a Jan. 30, 2026, in-service date.

Dominion (NYSE:D) also reviewed its own supplemental projects, amounting to nearly $10 million.

Five 230-kV breakers and six disconnect switches at the company’s Clover substation are at the end of their lives and experiencing increased maintenance issues and difficulty sourcing replacement parts. The work, which is in the engineering phase, is expected to cost $2.75 million with a projected in-service date of June 1, 2023.

Dominion has identified a need to replace $2.36 million in 230-kV equipment at the North Anna substation in Virginia. The work is currently in the engineering phase and is projected to be in-service on Aug. 30, 2023.

The company is seeking to replace its Davis TX#2 168-MVA, 230/69/13.2-kV transformer bank because of its 32-year age, degradation of components and the basic insulation level being below standard. The project, currently in its engineering phase, is estimated to cost $4.5 million and be completed by June 30, 2023.

Dominion has also submitted three new requests for substations in Loudoun County, each with a total load in excess of 100 MW. The company has also identified overloads on a 230-kV line on the Brambleton-Evergreen Mills for the loss of the Brambleton-Poland Road line. It is in need of a temporary solution to avoid the overload and provide flexibility for future construction outages.

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Counterflow: More Happy Talk

Fact

Inside our industry it’s no secret that net zero — or anything like it — is going to be incredibly expensive if you want to keep the lights on.

There are the global challenges I’ve written about,[1] with the U.N. highlighting the most recent shortfalls.[2] There’s our national picture, where past attempts to make net zero look easy have been discredited.[3] And we’ve had rosy state modeling that, as I’ve pointed out before, would leave California without any electricity for big parts of winter months;[4] ditto for Germany.[5]

The most recent reality checks come from David Rapson and James Bushnell[6] and from The Economist.[7] The case mounts for a Plan B.[8]

Fantasy

Meanwhile there remains a fantasy that net zero is feasible and affordable — because it must be.

Thus Hurricane Ian brought not only mass destruction and suffering, but also predictable attempts to find a silver lining for a net-zero future.

CNN, “60 Minutes,” Newsweek, Yahoo, Fortune, Slate, The Atlantic, MSN, Time, The Hill, Axios, RMI and many others, even the New York Post, ran gushing stories about the Babcock Ranch planned community in southwest Florida, claiming that the lights stayed on during the hurricane because of solar panels and battery storage.[9] Sample headlines:

      • “This 100% solar community endured Hurricane Ian with no loss of power and minimal damage”[10]
      • “The U.S.’s ‘first solar-powered town’ kept its electricity and water running during Hurricane Ian — and became a model for how to adapt to climate change”[11]
      • “Babcock Ranch: Solar-powered ‘hurricane-proof’ town takes direct hit from Hurricane Ian, never loses electricity”[12]
      • “Solar-powered town in Florida kept lights on during Hurricane Ian”[13]

One Wee Problem: Ain’t So

Babcock Ranch saw its last sunlight around 3 p.m. on Sept. 26 as Hurricane Ian covered southwest Florida. From then on, there was negligible sunlight for the solar panels to provide power to homes or to recharge the battery, until 9 a.m. on Sept. 29.[14] Total time without sunlight: 66 hours.

After loss of sunlight, the 10-MW/40-MWh battery[15] could have powered 10,000 homes for four hours at average electric home usage of 1 kWh,[16] leaving about 62 hours without anyone getting any power from the solar/battery system at Babcock Ranch.[17]

So how did the lights stay on? The same way they stayed on wherever distribution lines[18] weren’t taken out by Ian: fossil fuel and nuclear generation; nothing to do with solar generation and battery storage.

To summarize, the solar/battery system could have supplied power to some homes for four hours during Ian, while fossil fuel and nuclear generation supplied power for about 62 hours.

One News Organization Got it Right

One news organization got the story right by interviewing the CEO of the company developing Babcock Ranch. Ironically, it’s not even a U.S. news organization, but Canadian.[19] In an interview this CEO honestly says: “We’re the first solar power town in America. We have 150 MW; that’s 700,000 panels on about 340 hectares. Now that’s all fine and good, but when a storm comes in like Ian did, and there’s cloud coverage for a long period of time, you can no longer depend on that solar energy. So we then had to draw from the main utility.”

What a concept: interviewing someone who actually knows something. But for major U.S. media, it’s the happy talk that matters.

Columnist Steve Huntoon, principal of Energy Counsel LLP, and a former president of the Energy Bar Association, has been practicing energy law for more than 30 years.

[8] Please see my column referenced in footnote 1.

[14] To confirm this, please go to www.wunderground.com and search location “KFLPUNTA222” (Babcock Ranch DM). Under Weather History enter a day, click View, and then scroll down to Solar Radiation data (please note that full sunlight is about 1,000 W/square meter). The data at this location are confirmed by other nearby stations, KFLPUNTA361 and KFLLABEL37.

[16] According to Energy Information Administration data, average home electric usage in Florida is 1,142 kWh/month. https://neo.ne.gov/programs/stats/pdf/145_Residential.pdf. Excluding space heating/cooling (36% of total usage, https://www.myfloridahomeenergy.com/help/library/choices/home-energy-basics/#sthash.TVHeGPY8.dpbs ) because temperatures during Ian were 70 to 80 degrees Fahrenheit, leaves 731 kWh/month or 1 kWh. Average home usage of 1 kWh for 10,000 homes aggregates to 10 MWh (the maximum hourly output of a 10 MW battery), thus draining a 40-MWh battery in four hours.

[17] The solar/battery project is reported to power many more homes than in Babcock Ranch proper. If the project had been limited to supplying just Babcock Ranch’s 2,000 existing homes (https://babcockranch.com/babcock-ranch-exceeds-2000-home-sales/), the battery could have lasted 20 hours, with fossil fuel and nuclear generation supplying the remaining 46 hours.

[18] Power can also be taken out by loss of transmission (as opposed to distribution) lines, but there was reportedly no loss of transmission lines from the hurricane. RTO Insider, Nov. 1, 2022, page 3.

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PJM MIC Briefs: Nov. 2, 2022

VALLEY FORGE, Pa. — The Market Implementation Committee last week overwhelmingly adopted a problem statement and issue charge to explore whether PJM should account for local issues, such as state and local policies, that may impact the development of the net cost of new entry (CONE) in a region.

The measure passed Wednesday with 97% of votes supporting.

While there was general agreement among stakeholders that the issue should be addressed by PJM, there were questions about how far the scope of the issue charge should go.

James Wilson, a consultant to state consumer advocates, likened making changes to the derivation of net CONE to changing the length of one leg of a stool without looking at the others, with the stool in the metaphor being the capacity market and the impact being the tilting of the markets in favor of certain sectors.

“That would cause money to slide off the stool and into their pockets,” he said.

That could be mitigated by implementing the changes to net CONE in the next quadrennial review, when other factors related to the capacity market can also be considered, or by widening the issue charge.

Gary Helm, PJM lead market strategist, said it wasn’t the RTO’s intention to limit discussion and that he did not believe the stakeholder process would yield such results.

Approval to Merge DER and DIRS Subcommittees

Stakeholders approved by acclamation to support merging the Demand Response Subcommittee and the DER & Inverter-Based Resources Subcommittee into a new Distributed Resources Subcommittee (DISRS).

PJM’s Peter Langbein and Scott Baker, the former chairs of the DRS and DIRS, respectively, said the stakeholder composition of the two committees and the materials they reviewed were similar enough that they conduct their work in unison. They said it would be best to work in tandem, particularly when recommending manual changes.

The combined charter will also examine behind-the-meter generation and energy efficiency, in addition to the existing scope of the two committees: DR, distributed energy resources and inverter-based resources.

Independent Market Monitor Joseph Bowring said the committee’s charge would be too broad, which could institutionalize a separate system being created for inverter-based resources. Since the resources falling under the committee are part of the capacity market, he believes they should be addressed by the existing committee structure, which handles other resources.

MIC Endorses Proposal on Hybrid Resources

The committee endorsed a proposal to expand PJM’s hybrid resource rules — which are currently applicable only to solar and storage combinations — to now include all inverter-based resources (IBRs) paired with storage.

Day-ahead zonal load bus distribution (PJM) Content.jpgPJM’s proposal to revise its day-ahead zonal load bus distribution factors would draw off data for each hourly node of the most recent corresponding work day, rather than relying only on 8 a.m. from that date. | PJM

The proposal allows IBR and storage hybrids to participate in the energy market model created in the first phase of the hybrid resource design, which was implemented for classification and metering on Oct. 1. The energy market model is set to go live on June 1, 2023.

The package also broadens the definition of hybrid resources to include combinations of different types of generation, with or without storage, with the implication of allowing more resource types, such as hydro or gas paired with solar to participate under the provisions from the first phase. (See PJM Releases Phase 2 of Energy Transition Study.)

The language also contains clarifications to PJM’s EcoMax parameters and corresponding uplift rules.

The proposal will require approval by FERC.

First Read on Changes to Day-ahead Zonal Load Bus Distribution Factors

PJM’s Amanda Martin presented a first read of proposed changes to the RTO’s day-ahead factor analysis, which would shift from calculating each hourly node based on state estimator load for that node as of 8:00 AM on that day of the prior week to instead use the previous week’s real-time data from each hour.

For example, instead of basing expectations for 10 a.m. on Nov. 8 on 8 a.m. data from Nov. 1, the corresponding real-time data from 10 a.m. would be pulled.

The lookback period would use the most recently available day of the week where all 24 hours of data are available, meaning if an hour of data was unavailable for Nov. 1 in the previous example, that date would be skipped and data would be pulled from Oct. 25.

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PJM General Session Focuses on Clean Energy Transition

CAMBRIDGE, Md. —
PJM’s biannual General Session last week focused on how to ensure both reliability and equity during the transition to a clean energy-based generation mix.

NERC CEO Jim Robb moderated the first panel, introducing it by saying that reliability, environmental impact and affordability will all be challenged during the transition to relying on renewable power. Over the next 10 years, NERC expects to see increased risk from extreme weather and tight supply margins as the decommissioning of fossil fuel generation runs up against increasing demand from electrification.

Jeff Craigo of ReliabilityFirst said the regional entity has had success with an initiative to survey generation facilities’ winterization efforts, which has allowed it to share those experiences across the industry.

Peter Brandien, ISO-NE vice president of system operations and market administration, said the RTO is focusing less on specific percentages of capacity, and more on understanding what kinds of resources are available and their characteristics.

The RTO’s response to the transition has centered on four pillars, Brandien said: handling the influx of clean energy resources; a supply of balancing resources to preserve reliability; maintaining resource adequacy to meet demand when solar and wind power aren’t available; and having adequate transmission to import more renewable energy and to ensure renewable resources aren’t constrained when they’re needed.

Resource adequacy in particular has been challenging within New England. Unlike other areas of the country where the problem is getting through the peak load day and resetting for the next, New England has limited storage (LNG, oil, hydro or long-duration batteries) and can run short of supply, particularly during extended cold weather. Siting has also proven to be another challenge, and Brandien noted the struggle of the New England Clean Energy Connect transmission line.

Confidence in the reliability of the grid is crucial to industries looking to make investments, which Brian George, lead of Google’s energy regulatory and policy engagement team, said is reflected in the company’s heavy investments in PJM.

“Our users expect and demand reliability all the time and everywhere, so that’s at home, that’s in the office. … Whenever they pull up the browser, they expect us to be there,” he said.

To meet the company’s climate goals, he said Google has shifted its focus to the procurement of energy for when and where it’s needed, rather than the installation of additional renewable resources. He said the open markets, which have created affordable and reliable power in PJM, will play a key part in addressing that focus while meeting its growing demand.

Nancy Bagot, senior vice president of the Electric Power Supply Association, said the transition is the time to double down on competition to encourage more innovation, while shielding customers from the risks of finding the right balance of resources. There will have to be an acknowledgement that markets are being asked to break new ground, she said, and the conversations on how to do so will need to remain grounded in reality and based on the voices of reliability experts.

That will involve reimagining the capacity market in what it signals and procures for different regions of the country, including a look at what the mix of capacity available is, rather than the raw amount in the market, Bagot said.

Bobby Jeffers, program manager at the National Renewable Energy Laboratory, spoke about the lab’s efforts to improve the models, tools and calculators available for gauging reliability. Incorporating a better understanding of how supply chains function and geopolitics is necessary for creating modeling for a system that works.

NREL is also upgrading its Interruption Cost Estimate calculator to reflect the societal costs of extended outages, Jeffers said. The economic impacts currently incorporated into the tool fail to reflect the toll outages can take on customers.

Responding to the question of whether FERC should play an activist role or take a more passive, judicial approach to the transition, the panelists largely agreed that stability and deference to RTOs were preferable.

Brandien said that grid operators know their regions best and they can carry out their responsibilities more effectively without NOPRs and filings confusing the waters. George said it’s important that if FERC has a preference on a policy, it should make it known and take the lead, rather than leave RTOs in the dark.

Equity and Environmental Justice

The second panel focused on ensuring that the costs of the transition don’t fall disproportionately on disadvantaged communities and examining how to reconcile the need to expand energy infrastructure and the burden it often places upon the communities that host it.

One of the largest challenges in ensuring the equity of wholesale energy markets remains the lack of public knowledge about their functioning, said Damali Rhett Harding, managing principal for the Regulatory Assistance Project.

“How do we incorporate equity into a marketplace that probably 99% of Americans don’t realize exists?” she questioned.

To provide equity in energy, she said companies need to examine the procedures that prevent people from participating in the siting process.

Beyond just educating the neighbors of a proposed project, former U.S. Rep. Joseph P. Kennedy III (D-Mass.), now managing director of Citizens Energy, said developers and utilities should explore ways to ensure that the expansions directly benefit those communities. He pointed to a project in which his nonprofit partnered with a utility to invest in a large transmission project in California’s Imperial Valley, and then used the profits it earned to construct a 30-MW community solar installation in the city of Calipatria. In addition to improving reliability, the solar project provides about $500 in annual savings every year over 20 years to 12,000 low-income households in a region where temperatures can exceed 110 degrees Fahrenheit, he said.

Such arrangements can prove worthwhile even to for-profit companies by alleviating residents’ concerns that large transmission projects could lower property values or disrupt their neighborhoods with no visible benefit to them, Kennedy said. The costs of the delays or resiting of projects can often well exceed the expense of profit sharing with those communities, he argued.

Delaware Public Service Commissioner Harold Gray, who moderated the panel, said incorporating more voices can help companies find more forms of value than immediate profit alone. In his work on the commission, he has had success showing utilities that by keeping their customer’s interests in mind, they can discover new customers and potentially expand profits.

Former FERC Commissioner Colette Honorable, now a partner at Reed Smith leading the firm’s energy regulatory group, noted that getting all parties on board with a project in the early phases can reduce the likelihood of prolonged, and expensive, delays at FERC and the federal courts.

“You’re in trouble if you have a matter pending and the first time you hear them is when they object,” she said.

Likewise, she said incorporating equity into the work done by RTOs can be accomplished by examining what voices are missing at the table and including those stakeholders who aren’t represented. On public education, she said FERC’s new Office of Public Participation has been making strides in ensuring that individuals at all levels are empowered to make their concerns heard.

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Monitor Finds PJM’s 2023/24 Base Residual Auction Competitive

The 2023/24 Base Residual Auction held by PJM in June yielded competitive results, the RTO’s Independent Market Monitor announced in a report released last month, owing largely to the implementation of a 2021 FERC order reworking the derivation of the market seller offer cap (MSOC).

Monitoring Analytics’ report, released Oct. 28, said the shift from basing the MSOC off the net cost of new entry (CONE) to using the avoidable-cost rate (ACR), as ordered by FERC, addressed concerns about the ability to exercise market power and uncompetitive outcomes leading to customers being overcharged. (See PJM Capacity Prices Crater and FERC Backs PJM IMM on Market Power Claim.)

“The net CONE times B offer cap assumed competition where it did not exist and led to noncompetitive outcomes and led to customers being overcharged by a combined $1.454 billion in the 2021/2022 and 2022/2023 BRAs,” the Monitor said. “The logical circularity of the argument, as well as the fact that key assumptions are incorrect, means that the [Capacity Performance] market seller offer cap was not based on economics or logic or math.”

Despite believing the auction succeeded in securing competitive results, the Monitor wrote that the Reliability Pricing Model still has many components of a “significantly flawed market design.” These include the shape of the VRR curve; the participation of demand response resource in the capacity market; capacity imports; and the overstatement of intermittent capacity offers.

In addition to taking issue with intermittent resources offering capacity at a higher rate than permitted by their capacity interconnection rights, the Monitor said exempting those resources from the must-offer rule raises market power issues stemming from the ability to withhold supply.

“The failure to apply the must-offer requirement will create increasingly significant market design issues and market power issues in the capacity market as the level of capacity from intermittent and storage resources increases and the level of demand-side resources remains high. The failure to apply the must-offer requirement consistently could also create price volatility and uncertainty in the capacity market and put PJM’s reliability margin at risk,” the report says.

The report called for a consistent definition for capacity that includes being a physical resource at the time of the auction for all resource types. That requirement is not currently being applied to DR, nor to energy efficiency, both of which the Monitor said should be shifted to the demand side of the market. It also wrote that EE is accounted for in PJM’s load forecasting and the payments such resources receive don’t provide added incentive for participant behavior.

The use of a sloping VRR curve procures excess capacity and masks the flaws of “permitting the participation of inferior demand-side resources in the capacity market” by avoiding the need to rely on those resources, the Monitor argued. It said that the use of a vertical demand curve “equal to expected peak load plus a required reserve margin” would reduce capacity payments by nearly $1 billion. The report noted that the IMM’s recommendation was to rotate the curve halfway toward vertical for the current quadrennial review, while PJM opted for a curve rotated a quarter of the way.

“Use of the VRR curve increased the purchase of capacity [by] 10.1% and increased the total load payments for capacity by $983 million, or an increase of 81.1% compared to a vertical demand curve,” the report says.

Adam Keech 2022-10-18 (RTO Insider LLC) FI.jpgAdam Keech, PJM | © RTO Insider LLC

During an Oct. 18 panel at the Organization of PJM States Inc.’s Annual Meeting, PJM Vice President of Market Design Adam Keech said that a vertical curve would temporarily lead to lower capacity prices, but in the long term, it would replicate the very volatility that led to the creation of the capacity market in 2005. That volatility could lead to more generation owners deciding to retire their units, ultimately driving prices higher.

Though it hailed the shift to basing the MSOC on the ACR going forward, the Monitor that the ACR definition should be reworked to be based on the cost of producing additional capacity. Currently it’s defined in the tariff as the costs of operating a generator for the given delivery year.

“Avoidable costs are the marginal costs of capacity and therefore the competitive offer level for capacity resources and therefore the market seller offer cap. Avoidable costs are the marginal costs of capacity, whether a new resource or an existing resource,” the report says.

The report found that 139,399.5 MW of generation and DR cleared in the BRA, with a reserve margin of 21.6% and a net excess of 7,835.3 MW over the reliability requirement. The net excess increased 175.1 MW up from the 2022/23 BRA, which had an excess of 7,660.2 MW.

The report said that a vertical demand curve would have reduced revenues by 44.8%, bringing the total from auction clearing prices, quantities and uplift from $2,196,444,791 down to $1,212,977,260.

The accuracy of the peak load forecast also had a “significant impact on the auction results,” with the forecast for the third incremental auction being on average 3.1% lower than the forecast for the corresponding BRA. If the forecasted results had been 3.1% lower, total auction revenues would have been $1,729,724,427, a decrease of $466,720,364, or 21.2%, compared to the actual results.

The report found that the 15.5% decrease in the Commonwealth Edison capacity emergency transfer limit (CETL), amounting to 1,058 MW, did not have an impact on the auction results.

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NYISO Identifies 35 Projects for Narrowed SRIS Scope

NYISO has proposed narrowing the system reliability impact study (SRIS) scopes for 35 generation projects in the queue in order to expedite the interconnection process.

The Transmission Planning Advisory Subcommittee on Nov. 1 unanimously recommended that the Operating Committee approve the proposal at its next meeting, currently scheduled for Nov. 17.

The SRIS evaluates the impact of a project on the existing electric system, including future firm transmission projects. As a growing number of projects request interconnection in New York, the ISO has sought to find ways to move the SRIS process along in a timelier manner without jeopardizing grid or project reliability. (See “Interconnection Queue Streamlining,” NYISO Operating Committee Briefs: Oct. 13, 2022.)

Thinh Nguyen, senior manager of interconnection projects, said that certain evaluations in the projects’ studies were removed because they were identified as being “redundant” or could be “conducted at a later stage.” There are also “informal ways” for developers to provide the additional information related to the study, he said.

Not every SRIS scope was narrowed in the same way. Mark Reeder, representing the Alliance for Clean Energy New York, asked how the ISO determined which evaluations to remove from each of the scopes and why they were not removed from every identified project.

Nguyen responded that they went on a “case-by-case” basis because not every scope had a particular evaluation; some projects’ evaluations were already ongoing; and other scopes already completed certain evaluations.

Howard Fromer, who represents the Bayonne Energy Center, asked whether removing the evaluations from the SRIS scopes required modifications or updates to any ISO procedures, manuals and tariffs, or if this was simply within NYISO’s discretion.

Nguyen responded that no modifications or other changes were needed, with the only requirement being OC approval, as well as transmission owner sign off, as the ISO lacks the “unilateral authority” to make these changes outright.

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FERC Orders Clarification in ERO Budget Filing

Citing concerns about NERC’s accounting for costs related to the Electricity Information Sharing and Analysis Center (E-ISAC) in its 2023 Business Plan and Budget, FERC on Wednesday instructed the ERO to submit an array of additional information on the cost by early January (RR22-4).

The commission directed the additional compliance filing as part of its order accepting NERC’s budget, along with the business plans and budgets of the regional entities and the Western Interconnection Regional Advisory Board (WIRAB). NERC’s Board of Trustees approved the final budgets at its August meeting in Vancouver, following what board members called “the most comprehensive budget process” to date at the ERO. (See “Board Approves ERO Budgets,”  NERC Board of Trustees/MRC Briefs: Aug. 17-18, 2022.)

Next year’s NERC budget is set to rise to $101 million, up 13.7% from last year. The total amount includes $38 million for the E-ISAC, including the Cyber Risk Information Sharing Program (CRISP), an increase of 15.8% from the 2022 budget. (See NERC FAC Approves Final 2023 ERO Budgets.) NERC’s assessment will also rise by 11.1% to $87.1 million.

Budgets, Assessments Up Across the Board

Budgets and assessments for the regional entities are set to increase as follows:

WIRAB’s 2023 budget is set to decrease by 3.9% next year to $883,520; its $681,920 assessment represents a 2.4% decrease from last year’s level.

FERC accepted all the budgets in its order, while also granting NERC’s request for a waiver of its Rules of Procedure (ROP) to allow it to use $1 million from its Assessment Stabilization Reserve (ASR) to offset its 2023 assessment.

NERC also requested a waiver of the ROP to allow MRO, NPCC, SERC and WECC to deposit penalty funds received between July 1, 2021 and June 30, 2022 — totaling $23.9 million — into their ASRs. FERC granted this request as well, along with approving WECC’s application to use $595,000 in funds gifted upon the dissolution of Peak Reliability in 2019 for two technology projects included in the RE’s business plan for next year.

E-ISAC Costs Require Follow-up

But the commission’s acquiescence came with strings attached in the form of the compliance filing that FERC demanded within 60 days of the order’s publication. Its direct inspiration is a comment submitted by the Edison Electric Institute in response to NERC’s original filing of the business plans and budgets.

EEI’s comment supported NERC’s budget overall; however, the size of the increase — NERC’s biggest budget hike since 2015 — spurred the organization to call for “a subsequent analysis to ensure the effectiveness of the expenditures.”

Specifically, EEI noted that a significant driver of the growth is the E-ISAC budget, which accounts for $5.1 million of the $12.2 million increase. The institute suggested that “all expenses associated with E-ISAC … should be detailed in separate line items,” and that electric industry stakeholders should also be given enough information to tell “whether other critical sectors are fully funding their participation” when they collaborate with the E-ISAC so that “electricity customers are not solely financially responsible for E-ISAC’s shared functions.”

ERO Enterprise budget (NERC) Content.jpgThe total ERO Enterprise budget, including the regional entities and WIRAB, is set to rise to $250.1 million in 2023, a 10.1% increase over the 2022 budget. | NERC

FERC agreed that its oversight duties would be better served by “additional transparency into certain E-ISAC costs” and ordered NERC to provide information on several aspects of the program’s operations. In addition, the commission asked NERC for data on E-ISAC’s relation to outside partners and vendors.

First, FERC asked for “a detailed explanation of costs attributable to E-ISAC” in light of what it called insufficient transparency about how the ERO allocated direct and indirect costs to the program in the 2023 budget. As an example, the commission listed NERC’s new Business (Information) Technology department, which has a budget item labeled “E-ISAC” but does not specify “whether the technology costs relating specifically to E-ISAC are directly allocated to E-ISAC or whether NERC indirectly allocates these costs among all program areas.”

To address this alleged lack of clarity, FERC asked that NERC explain which of the new department’s costs, if any, are attributable to E-ISAC. If the department’s budget item does not attribute costs directly to E-ISAC, then NERC must explain “why these costs are more appropriately allocated as indirect costs to all statutory program areas.” The ERO must also explain its written policies and procedures that determine how costs are allocated.

FERC also pointed to NERC’s proposed $5.3 million expenditure for capital software investments, $4 million of which is to be funded by loan proceeds. According to NERC, the investments “span across [its] Statutory Program and Administrative Program departments” and represent several cost categories. The commission questioned the assignment of fixed asset costs and ordered the ERO to be clearer about how these funds are to be allocated, as well as its policy on assigning loan funds to program areas and a breakdown of how the $5.3 million are to be distributed.

Concerns over Collaboration Fairness

Along with questions about the direction of funds, the commission raised questions about the E-ISAC vendor affiliate program, a membership plan for suppliers of hardware and software products to the electricity sector. The program provides three levels of annual membership for vendors; higher levels cost more but confer additional benefits, such as access to networking sessions at the GridSecCon security conference or participation in GridSecCon panels.

FERC said it “is generally supportive of increased collaboration between E-ISAC members and the vendor community,” but said it is not clear how the tiered structure supports this goal while preventing participating vendors from engaging in sales and other “business development opportunities.” The commission directed NERC to explain why it chose this structure for the program, how it promotes collaboration and information sharing, and how the ERO provides oversight of the program to prevent business development.

Finally, FERC claimed that NERC’s budget was not sufficiently transparent regarding the division of costs in efforts involving collaboration with the natural gas sector. In particular, the commission focused on CRISP, the operational costs of which are split between program participants and assessment carried out under Section 215 of the Federal Power Act. FERC feared that because natural gas-only companies do not pay Section 215 assessments, they do not contribute to CRISP operations to the degree that their counterparts in the electric sector do.

While FERC acknowledged NERC’s claim that “the natural gas industry provides the funding to support their own collaboration,” the commission also pointed out that NERC has said elsewhere that “natural gas-only participants will also have access to other E-ISAC benefits, such as the E-ISAC portal.” FERC said this makes it unclear whether gas participants will pay for all or only some of their E-ISAC costs. The commission therefore directed NERC to explain what additional costs gas companies incur while participating in CRISP and E-ISAC, and how they fund those costs.

[Correction: An earlier version of this article included a mistaken reference to the location of the NERC board’s August meeting.]

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Texas PUC Briefs: Nov. 3, 2022

ERCOT to Add Reliability Monitor to its Responsibilities

The Texas Public Utility Commission last week approved staff’s recommendation that ERCOT serve as the footprint’s reliability monitor, formalizing a two-year collaboration that has resulted in several enforcement investigations (54248).

The commission agreed to direct ERCOT to assume the reliability monitor duties and responsibilities as part of the consent agenda during its open meeting Thursday. With Chair Peter Lake out on personal leave, Commissioner Will McAdams led the meeting.

PUC staff said ERCOT has for years adopted reliability-related regulations that are found in the organization’s nodal protocols, operating guides and other binding documents. For the past two years, it has worked with the commission’s Division of Compliance & Enforcement to jointly monitor and investigate potential noncompliance with the grid operator’s reliability rules.

As the reliability monitor, ERCOT will gather and analyze data; protect confidential information; provide expert advice to commission staff during the investigation, prosecution and litigation of reliability-related enforcement proceedings; and work under the PUC’s direction.

A spokesperson said the grid operator will need additional staff to perform the monitor’s duties. Its budget will be funded through the system administration fee that has historically included the function’s costs, she said. ERCOT staff will begin performing the function “immediately.”

The Texas Regional Entity had served as the grid’s reliability monitor from 2010 until 2020. The PUC ended its contract with the agency over concerns it wasn’t getting its money’s worth. (See PUC Cancels Texas RE as ERCOT’s Reliability Monitor.)

The Texas RE enforces NERC’s federal reliability and security regulations, which are subject to FERC oversight, in the state. Most entities operating on the transmission system in the ERCOT region are subject to NERC’s standards.

The state’s Public Utility Regulatory Act requires the PUC to adopt and enforce rules related to ERCOT’s reliable operation of the region’s system. It also allows the commission to delegate the responsibility for adopting or enforcing these rules to an independent organization.

ENGIE Case Set for Hearing

The commission approved in part and denied in part ENGIE’s and Viridity Energy Solutions’ (NYSE:ORA) complaint against ERCOT regarding the settlement of ancillary services during the February 2021 winter storm (53377).

Lori Cobos (Admin Monitor) FI.jpgCommissioner Lori Cobos | Admin Monitor

The PUC approved a preliminary order that sets issues to be addressed, but it denied ENGIE’s request to depose commission staff. It also denied its staff’s request for a protective order from providing depositions as being too broad.

“The commission can’t be deposed, given our quasi-judicial role in this matter,” Commissioner Lori Cobos said. She said ENGIE could request to depose specific commission staff by name as fact witnesses, making staff’s request too broad.

The companies allege that the grid operator did not properly credit Viridity for providing responsive reserve service (RRS) during the storm and that ENGIE was assessed $47.7 million in charges for replacement RRS. They argue that Viridity should be credited $67.4 million to $140.6 million for providing RRS and that ENGIE should not be charged for the replacement service.

The commission referred the docket to the State Office of Administrative Hearings (SOAH) to conduct a hearing and issue a proposal for decision to resolve any contested issues.

Entergy Power Plant not Considered

The PUC did not take up Entergy Texas’ (NYSE:ETI-) application to construct its 1.22-GW Orange County Advanced Power Station in Southeast Texas, despite an administrative law judge’s approval of the project (52487).

The ALJ in September recommended the project’s approval but removed a hydrogen component and imposed a cost cap. The project’s costs have already risen from $1.19 billion to $1.58 billion in a year. Entergy’s plans the facility to be able to burn 30% hydrogen upon commercial operation and eventually support 100% hydrogen operation.

“We continue to believe that Day 1 hydrogen co-firing capability for [the facility] is in the best interest of our customers,” Entergy CEO Drew Marsh said during the utility’s third-quarter analysts call Nov. 2. (See related story, Entergy Learning from Florida to Improve Resilience.) He noted that Texas Gov. Greg Abbott has “indicated” his support for the plant’s hydrogen capability.

“Capped hydrogen capability is less than 5% of the total investment, and it provides a critically important option for fuel diversity and ensures the plant’s continued value at the low-carbon future,” Marsh said.

PUC Adds OK to ADER Pilot Project

The commission formally approved ERCOT’s Aggregate Distributed Energy Resource (ADER) pilot project, which was also approved last month by the grid operator’s Board of Directors (53911). (See ERCOT Board of Directors Briefs: Oct. 18, 2022.)

The project will evaluate how ADERs can support reliability, participate in the wholesale market and play a role in emergency situations.

“This is a victory for the stakeholder process all the way around, from the commission to ERCOT staff to the industry stakeholders to the average everyday consumers who were able to participate,” said McAdams, who spearheaded PUC’s involvement in the project with Commissioner Jimmy Glotfelty. “Big things have small beginnings, and I think this is going to be a big thing.”

“I think that this puts us in a driver’s seat of leading again. … We’re going to learn a lot from this,” Glotfelty said.

In other actions, the PUC:

    • denied El Paso Electric’s rehearing request to correct an error in one of its rate schedules. The utility filed an uncontested settlement with other parties to the proceeding in July that was approved by an administrative law judge in September (52195).
    • assessed a $72,000 administrative penalty to South Texas Electric Cooperative for failing to telemeter the appropriate resource status code and for failing to timely and properly assign its ancillary service capacity obligation in 2019 (53691).
    • agreed to open an investigation into Texas Excel Property Management for possible violations related to the denial of tenants’ rights to choose a retail electric provider in ERCOT’s footprint where retail customer choice has been introduced (54225).
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A New Era for Climate Action at COP27: ‘We Will be Holding People to Account’

U.N. climate conferences tend to open with stirring and urgent calls to action, and the 27th Conference of the Parties (COP27), which kicked off Sunday in Sharm el-Sheikh, Egypt, held true to form, with current geopolitical and economic realities challenging the rhetoric.

At last year’s COP26 in Glasgow, Scotland, 193 nations committed to coming to this year’s event with new, more ambitious targets for cutting carbon emissions, but only 29 have thus far delivered on those pledges, said Simon Stiell, the new executive director of the U.N. Framework Convention on Climate Change (UNFCCC).

“Today a new era begins, and we begin to do things differently,” Stiell told delegates at COP27’s opening plenary on Sunday.

“We will be holding people to account, be they presidents, prime ministers or CEOs … because our policies, our businesses, our infrastructure, our actions, be they personal or public, must be aligned with the Paris Agreement and [U.N.] convention. The heart of implementation is everybody, everywhere in the world, every single day, doing everything they possibly can to address the climate crisis.”

Stiell’s top priorities for the conference include across-the-board commitments to steeper emission reductions, solid financial support to help developing countries adapt to and recover from the damages of climate change, and new levels of transparency and accountability.

“Environmental integrity and the reliability of the commitments made are paramount,” he said. “I am not in the habit of rescinding on my word; I firmly expect all parties to act the same way. Stick to your commitments; build on them here in Egypt. I will not be a custodian of backsliding.”

Further, the pull of current political and economic crises — such as inflation, the war in Ukraine, and energy and food insecurity — must not be allowed to slow progress on climate action, said Egyptian Minster of Foreign Affairs Sameh Shoukry, who is also serving as COP27 president.

“If some people think that such challenges will hamper international collective action in the field of climate action, we here in Sharm el-Sheikh need to prove the contrary,” Shoukry said. Conference outcomes must “show the whole world that we are aware of the challenge awaiting us and that we have the political will to counter it.”

He called for “moving from negotiations and pledges to an era of implementation, as well as the acceleration of implementation,” while also “scaling up ambitions according to countries’ capacities and the nature of their resources.”

Alok Sharma, the U.K. official who led COP26, agreed that in the face of ongoing extreme weather events — such as the catastrophic flooding in Pakistan and Nigeria — “we must find the ability to focus on more than one thing at once. … This conference must be about concrete action.”

1.5 Alive, Barely

Whether these strong words will translate into action remains to be seen as the conference unfolds over the next two weeks, with national leaders expected to begin their statements of progress and new commitments on Monday. President Biden is scheduled to be at the conference on Friday.

The legacy of COP26 was to keep the goal of limiting the increase in the average global temperature to 1.5 degrees Celsius alive — barely — and Sharma reported that if all emission-reduction commitments made at that conference were kept, worldwide emissions in 2030 would be about 6 GT less than at present.

“That’s the equivalent of 12% of today’s global annual emissions” but would still result in a 1.7-degree increase in global warming, he said.

A recent report from UNFCCC suggests that those figures may be overly optimistic. According to the report, current commitments from the 193 countries that signed the Paris Agreement could result in a 2.5-degree increase. By 2030, carbon emissions are on track to increase 10.6% over 2010 levels, the report said.

Past 2030, emissions may not increase but still do not achieve the radical and sharp decreases that are needed, the report says. Such figures “could not be sharper, stronger or more sobering,” said Hoesung Lee, chair of the U.N.’s International Panel on Climate Change (IPCC).

Lee sees action on climate change as caught in a self-defeating cycle. “We have the technology and the know-how to tackle climate change, but these options are limited by the availability of finances, [and] adaptation options are limited by global warming levels. … Therefore, the prerequisite to a successful adaptation is ambitious mitigation.

“Adaptation gaps, especially in developing countries, are particularly driven by widening disparities between the cost of adaptation and financing available [for] adaptation,” he said. “We can achieve the greatest gains by prioritizing finance to reduce climate risks for low-income and marginalized communities.”

Fit-for-purpose Finance

Sharma, Shoukry and Stiell joined Lee in urging action to provide developing nations with the hundreds of billions they need to rebuild from the devastating impacts of extreme weather they have sustained to date, commonly referred to as “loss and damage.”

These countries, who produce only a small amount of the world’s greenhouse gas emissions, have long argued that the top emitting countries, like the U.S., should pay restitution.

But climate change negotiations in past decades have been “remarkably polarized, which has slowed down progress” and raised a range of concerns, particularly on finance, Shoukry said.

Developing nations are still waiting on the $100 billion per year that developed nations pledged to help them deploy clean energy technologies, when the original Paris Agreement was signed in 2015, Shoukry said. “The financing currently available focuses on curbing emissions and not adaptation efforts. Also, most of the financing is based on loans,” he said. “We do not have the luxury of continuing this way.”

Solutions must be found that “prove we are serious about not leaving anyone behind,” he said.

Stiell agreed. “We must cement progress on these critical work streams [of] mitigation, adaptation finance and, crucially, loss and damage. We need to enable enhanced finance to flow to addressing impacts. What is said in these negotiating rooms has to be reflected in the urgency of what is happening outside. …

“Let’s look closer at how the global financial architecture can be made fit for purpose in line with the Paris commitments,” he said. (See related story, COP27: Will Countries Step up on Climate, Financial Commitments?)