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August 20, 2024

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SPP Unveils Markets+ Governance Structure

SPP last week rolled out the governance structure that will oversee the first developmental phase of Markets+, the RTO’s day-ahead and real-time market in the Western Interconnection.

The RTO said Markets+ will provide “fully independent governance” from day one and give Western stakeholders a “meaningful say” in the market’s implementation.

Antoine Lucas, SPP’s vice president of markets who is responsible for overseeing the Markets+ launch, said the grid operator has always relied on the “integrity” of its governance model.

“The model designed to govern Markets+ builds on that legacy of success,” he said in a statement. “It will ensure stakeholders from across the Western Interconnection … all have a voice in the design, development and administration of Markets+.”

Staff shared further details of the governance model during a webinar last Thursday. Developed last year with western stakeholders, it is essentially the same process found in SPP’s final service offering for Markets+. The model will be used to develop tariff language, protocols and governing documents in a package to be approved by stakeholders and filed with FERC. (See SPP Issues Final Markets+ Proposal.)

SPP Director Steve Wright likened it to the final service offering to Markets+’s constitution.

“We’ll be seeking to act consistently with that. It really does set the roles and responsibilities for all of the governance,” Wright said during the webinar.

Wright will chair the Interim Markets+ Independent Panel (IMIP), which will provide independent oversight and the top level of decision making during the market’s first developmental phase. He will be joined by fellow independent directors Elizabeth Moore and John Cupparo. Any actions taken by a simple majority on Markets+ tariff language will be presented to the full SPP board and filed with FERC.

Wright, a former Bonneville Power Administration administrator and CEO of Washington’s Chelan Public Utility, and Cupparo, a former senior executive at Berkshire Hathaway Energy and WECC board member, bring extensive experience in the Western Interconnection.

“I encourage folks to embrace this opportunity, and I really look forward to moving through this process as quickly as the stakeholders would like,” Cupparo said.

“Technically, if there are disputes, they could come to the IMIP for resolution,” Wright said. “We would certainly hope and encourage that there will be no disputes that we would need to resolve. We really would like to see folks in the West deciding how they want this thing to be put together in establishing their own leadership, and that we are merely providing support for that.

“I want to really emphasize this is your market design, not SPP’s market design. You have the ability to define how this will go,” he said. “Our role is to try to manage the process in a way to make sure that you get to the substantive outcomes that you want. We’ll certainly be encouraging collaborative discussions that lead to decisions driven by Western stakeholders and not driven by the IMIP.”

MIP, IMIP, MSC and MPEC

The Markets+ Independent Panel (MIP), a five-member panel independent from Markets+ participants and stakeholders, will eventually be established and replace the IMIP for the market’s second phase of development.

SPP staff had originally intended to stand up the MIP for the first phase, but stakeholders indicated they preferred a truly independent board, SPP General Counsel Paul Suskie said. More than two dozen participating organizations provided comments during the process.

The IMIP — and eventually the MIP — will oversee a structure that includes a Markets+ State Committee (MSC), a Markets+ Participants Executive Committee (MPEC), and multiple working groups and task forces, including the Market Design and Seams working groups and the Greenhouse Gas Task Force.

The MSC will be comprised of regulators from each state in the Markets+ footprint: Arizona, Colorado, Idaho, Montana, Nevada, New Mexico, Oregon, Utah, Washington and Wyoming. The group is designed to advise the MIP, MPEC and working groups on policy issues and initiative prioritization.

Eric Blank, chair of the Colorado Public Utilities Commission, is leading the effort with the Western Interstate Energy Board to draft the MSC’s charter and formation efforts. Blank and SPP staff will update the board on Markets+ and the MSC during a Thursday webinar.

The MPEC offers a forum for Markets+ market participants and stakeholders to discuss issues related to the market’s administration and advancement, including establishing working groups, proposing tariff amendments and administrative rate changes. SPP staff is drafting charters that include each group’s purpose, scope and representation; they will be reviewed and voted on during the committee’s first meeting April 18-19 in Westminster, Colorado.

MPEC meetings are open to all stakeholders, but only entities that execute a market participant Phase One funding agreement or a stakeholder Phase One participation agreement are eligible to appoint a representative to the committee.

Markets+ has attracted 10 participants and several stakeholder groups, including the American Clean Power Association, The Energy Authority and Western Resource Advocates.

Western stakeholders and SPP staff spent more than nine months developing the governance structure. Staff said that having reached a critical mass threshold for Markets+ participation earlier this year, it has executed additional funding agreements. (See SPP Moving Quickly on Markets+’s Development.)

“From the overall board’s perspective, we are very encouraged by the commitment to the funding agreements and rapidity with which they were put in place,” Wright said. “It has certainly caused us to accelerate all of our activities, including pushing forward the establishment of this governance structure and the establishment of the IMIP.”

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Enviros Demand NJ Move Faster on 100% EV Rule

Supporters of New Jersey’s efforts to adopt California’s Advanced Clean Cars II (ACC II) rule on Monday urged state officials to move faster, saying the state lags others and is in danger of missing the crucial year-end deadline to enable the rule to cover 2027 vehicles.

More than two dozen speakers testified at a hearing held to outline the process for adopting ACC II; most were in favor of the proposal. New Jersey Department of Environmental Protection (DEP) officials were seeking input on whether the state should advance on adopting the rules. Supporters said because New Jersey is following California’s model, it has little flexibility in changing the rules, which would have to be adopted almost wholly or not at all.

“Our goal is to adopt by the end of the year, so that we can capture model year 2027,” Peg Hanna, assistant director, air monitoring and mobile sources for the DEP, said at the meeting. “But that is an extremely ambitious time frame for us to propose and adopt a rule.”

Most of the speakers said the state needed to make it happen to quickly reduce pollution, reap the economic benefits of jump-starting a new market and to compete with other states.

“The climate emergency demands it, and we’re so behind,” said David Pringle, a steering committee member of Empower New Jersey, noting that some states adopted the rules in time for model year 2026.  “We’re not a leader of the pack here. We’re behind the pack, and we have to catch up.”

Kit Kennedy, managing director of the climate and clean energy program at Natural Resources Defense Council, said the rules are key to helping slow the worsening impacts of climate change on the state, such as those from Superstorm Sandy in 2012.

“The transportation sector is the largest emitter of greenhouse gas emissions in the country and in New Jersey,” he said. “Zeroing out pollution from this sector will help to improve air quality and health while saving drivers money and reducing pain at the pump.”

The sole opposing voice at the hearing, Eric Blomgren, chief administrator and director of government for the New Jersey Gasoline, Convenience Store, Automotive Association (NJGCA), decried the rules. He said it is “fundamentally unfair” for the state to deny consumers the option to use gasoline vehicles.

“A transition should be done entirely through incentives to consumers, through free citizens making the choice themselves based on what makes sense for their life, their family and for their budget,” he said. He called the rules a “full government ban of a product which currently makes up 95% of the new sales market.”

Asked what prevented the state from moving swiftly, Hanna said it was a question of “internal prioritization” within the DEP, with the agency trying to adopt several different policies with limited administrative resources, some of which must be used to meet federal deadlines.

“It really is a balancing act,” she said, adding that “it remains our goal to adopt by the end of the year.”

Alex Ambrose, transportation and climate policy analyst at liberal think tank New Jersey Policy Perspective, urged the state to adopt the rules by April.

“Trying to reach these the goals that our state has set out without this rule in place for this year is like fighting with one hand tied behind our back, and we are sabotaging ourselves,” she said. “We’re like an out-of-state driver that is stuck in the left lane right now while other states are zooming past us towards the cleaner and healthier future.”

Ascending Sales Limits 

About 90,000 EVs are registered in New Jersey, a small fraction of the 6 million light-duty vehicles on the road, but a big jump up from approximately 30,000 EVs in the state at the end of 2019.

New Jersey’s Energy Master Plan calls for the state to deploy 330,000 light-duty EVs by 2025. Modeling by the International Council on Clean Transportation shows that New Jersey will reach 7.5 million EVs on the road by 2050 if the rules are enacted, and just 1.3 million EVs on the road if it isn’t, according to a presentation made at the meeting.

As adopted by California last August, ACC II requires car manufacturers in a state to provide an increasing percentage of zero-emission vehicles (ZEVs) for sale each year. It defines zero-emission vehicles as battery-electric, hydrogen fuel cell or plug-in hybrid. (See Calif. Adopts Rule Banning Gas-powered Car Sales in 2035.)

Oregon, Washington, Vermont, Virginia, New York and Massachusetts have followed suit in adopting the rules, while Delaware, Colorado, Washington, D.C., and Connecticut are considering doing the same. On Monday, Maryland said it would fast-track adoption of the rules. (See Maryland to Adopt California’s Advanced Clean Cars II Rule.)

The regulation starts with a 35% ZEV sales requirement for model year 2026, increasing to 68% in 2030 and reaching 100% in 2035. 

ACC II also includes increasingly stringent low-emissions vehicle standards aimed at reducing tailpipe emissions of gasoline-powered cars and heavier passenger trucks sold in a state.

Not all clean vehicles qualify under the rules, however. EVs must have a range of at least 200 miles, and plug in hybrids must be able to drive at least 70 miles on a charge, said Rob Schell, DEP’s supervising environmental specialist. The vehicles also must include an onboard charger of 5.76 kW or higher that can charge the vehicle in four hours or less, and be equipped to plug into DC fast charging ports.

Creating Market Certainty 

Tom Van Heeke, senior policy advisor for EV manufacturer Rivian, said passing the rules before year’s end is crucial not only for “achieving climate goals and achieving prescribed emissions reductions targets but also for investment certainty and planning both within the auto industry and then in sort of adjacent industries.”

“One of the core purposes of the rule is to provide a clear, well-understood glide slope that everyone can build and plan around in their businesses,” he said.

Eve Gabel-Frank, speaking for ChargEVC, a research organization and coalition of advocates that promotes EV use, said that even with 90,000 EVs on the road, the state is far away from its 2025 goal of 330,000 and the adoption of ACC II is key to reaching the goal by providing a signal to EV manufacturers.

“The reality of this is manufacturers are going to prioritize supply of EVs to the ACC II states,” she said. “So, if we don’t adopt [the rule], New Jersey drivers will either go without EVs, or be forced to travel to neighboring states to purchase the vehicles they want, which also has the added negative effect of moving economic activity out of the state.”

Preparing To Transition

That need to plan and prepare was echoed in a recent report by the New Jersey Coalition of Automotive Retailers, which found that the market sector still needs preparation for the rapid transition from gasoline and diesel vehicles to EVs.

In a study conducted in September and just released, the organization surveyed its members to learn what car manufacturers are requiring franchise auto dealers to complete, install or purchase to “prepare their dealerships for the EV revolution to come.”

“New Jersey’s electrification process will take years, if not a decade to really pick up momentum,” the report said. “Most manufacturers have committed themselves to being all or mostly electric in a few decades. While dealers support electrification and stand ready to invest in EV infrastructure, they are reluctant to invest too much too soon while there is limited availability on product, in addition to the sheer cost of electrification.”  

The report said dealers expect to spend $151 million on preparing for greater EV adoption by consumers, and most manufacturers have a plan to electrify their franchises within the next 15 to 20 years. Twenty-seven out of 33 dealerships in the survey said they have started or are starting the EV process, the report found.

“The biggest obstacle to electrification facing the dealership body is electricity itself,” the report concluded, saying that the organization should conduct another study in a year.

“Dealership principals from a wide variety of brands expressed concern about whether there is currently enough power or electrical infrastructure to accommodate every automobile franchise in the state, or enough infrastructure to support home chargers for customers, which several principals also expressed concern over.

The concern for some centered on the cost of the electrical upgrades and the timeline for electric companies to install those upgrades,” the report found.

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EPA Poised to Approve California Clean Truck Rules, Report Says

Good news is reportedly on the way to the California Air Resources Board regarding federal approval for its Advanced Clean Trucks regulation, which will require manufacturers to sell an increasing percentage of zero-emission trucks each year.

The Washington Post reported on Monday that the EPA has decided to grant waivers to CARB for Advanced Clean Trucks and two other regulations. The Post cited three unnamed sources who had been briefed on the plans.

As of Monday, EPA hadn’t made a formal announcement on the waivers.

CARB needs the EPA waivers because vehicle emission standards in the three regulations differ from federal standards. Under the federal Clean Air Act, a waiver may be issued if California’s standards are at least as stringent as federal standards. The state must receive the EPA waiver before it may enforce the rule.

The zero-emission sales requirements of Advanced Clean Trucks, which apply to medium- and heavy-duty vehicles sold in the state, are scheduled to take effect in 2024.

The waiver decision also has implications for other states that have adopted California’s Advanced Clean Trucks rule. Those include Washington, Oregon, New York, New Jersey, Massachusetts and Vermont.

An EPA spokesperson didn’t answer a question from NetZero Insider on Monday regarding whether the agency had decided to approve the waivers. She also didn’t specify when a decision would be made.

“EPA is working to issue its decisions on the waivers before us as expeditiously as possible,” the spokesperson said in an email.

A CARB spokesperson on Monday referred questions to the EPA, saying that CARB is “not aware of anything new on this.”

Monday’s news follows a report last year saying that EPA was considering a partial denial of the waiver for Advanced Clean Trucks that would impact the regulation’s first few years. That news report also cited an unnamed source. (See CARB Awaits EPA Decision on Advanced Clean Trucks Rule.)

EPA told NetZero Insider at the time that it was just getting started on the process for reviewing the waiver requests. EPA published an initial notice regarding the waivers in June, followed by a public hearing later that month. The deadline for written public comment was Aug. 2.

The Post reported that approval of the waivers was planned for earlier this month but was delayed because of “last-minute complications.”

The zero-emission sales requirements in Advanced Clean Trucks are based on vehicle classification. For Class 2b and 3 trucks, such as step vans and city delivery trucks, the rule requires 5% ZEV sales in 2024, increasing to 55% in 2035. ZEV sales requirements for Class 7 and 8 tractors range from 5% in 2024 to 40% in 2035.

In addition to Advanced Clean Trucks, CARB is awaiting an EPA waiver for the Heavy-Duty Low NOx Omnibus Regulation, which aims to reduce emissions of nitrogen oxides from trucks. A waiver is also pending for an amended emission warranty regulation that extends emissions warranty periods for heavy-duty diesel trucks in model years 2022 and later.

The waiver discussion comes as CARB is poised to approve another zero-emission truck regulation, Advanced Clean Fleets. The regulation would cover three types of fleets: drayage, state and local, and fleets deemed high priority. The regulation would require some or all new trucks added to the fleets to be zero-emission starting in January 2024. (See CARB Examining Obstacles on Road to ZEV Fleet Adoption.)

The regulation may go to the CARB board for final approval as soon as next month.

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FERC Dismisses Complaint over Con Ed Wholesale Distribution Rate

FERC on Thursday denied a New York company’s complaint against Consolidated Edison (NYSE:ED), saying it did not provide any evidence that the utility’s wholesale distribution service (WDS) rate was unjust or unreasonable (EL23-8).

There is little information online about the company, called Cubit Power One. According to an application filed with the New York City Industrial Development Agency in 2014, it is a special-purpose entity created “to develop green manufacturing facilities” seeking to build an “energy-efficient packaged ice manufacturing facility with on-site power generation” on Staten Island, with plans to eventually turn it into the city’s first carbon-capture plant. Its listed website is defunct.

That on-site generator, an 11-MW combined heat and power unit, was at the center of Cubit’s complaint. It told FERC that revisions Con Ed proposed making to its WDS rate in response to a New York Public Service Commission proceeding would severely reduce the income the company received from selling the unit’s extra power onto the grid.

The WDS rate is based on electric distribution companies’ average retail standby service rates, which are charged for the delivery of replacement energy that would normally be produced by distributed generators.

The New York PSC last March adopted a new cost allocation methodology for standby rates to “more accurately align individual customers’ contribution to system costs with the rates such customers pay, thereby sending improved price signals to those customers.” It required EDCs to submit revised standby and buyback rates (15-E-0751).

Con Ed’s current WDS rate is $7.59/kW/month and is charged when the amount being sold is over 1,500 kW. Cubit alleged that the new rate as a result of the PSC proceeding could be less than $0.20/kW/month. It argued that the new rate would allow Con Ed to “recover costs well in excess of Con Ed’s own cost of service.” Cubit also claimed that a Con Ed employee had sent an email saying the new rate would be $2.29/kW/month.

In response, Con Ed said that Cubit failed to include a later message from the email chain, which said that assumption was subject to change based on the PSC proceeding.

“Cubit’s arguments are based on conjectures regarding what may ultimately happen in the New York commission rate proceeding,” FERC said. The proposed rates submitted as part of that proceeding “are subject to change at any time.”

FERC noted that Con Ed will file an updated WDS rate once the PSC proceeding is completed, at which time it will determine whether it is just and reasonable.

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FERC Refuses Rehearing of PG&E-San Francisco Dispute

FERC on Thursday denied Pacific Gas and Electric’s request for rehearing in a case that has pitted the utility against the city and county of San Francisco for more than 18 years over PG&E’s application of its wholesale distribution tariff (WDT) to the municipal customers of San Francisco’s public utility (EL15-3-005, EL5-704-027).

The utility, the San Francisco Public Utilities Commission (SFPUC), operates a hydroelectric power project in the Hetch Hetchy Valley, near Yosemite National Park, and owns transmission lines that bring power from the Sierra Nevada to San Francisco.

It supplies electricity to schools, public housing tenants, libraries and municipal departments using the distribution system PG&E owns and operates in San Francisco — making the publicly owned utility both a customer and competitor of PG&E.

Since 2014, San Francisco has argued to FERC that PG&E has unreasonably denied distribution service to many of its 2,200 metered interconnection points under section 212(h) of the Federal Power Act.

The section prohibits mandatory retail wheeling such as forcing PG&E to deliver another utility’s power through its distribution lines. But it exempts cities and counties where “such entity was providing electric service to such ultimate consumer on the date of enactment of this subsection [Oct. 24, 1992].”

A FERC administrative law judge issued an initial decision in November 2016 that supported San Francisco’s argument. It cited the commission’s orders under Suffolk County Electric Agency (96 FERC ¶ 61,349) from November 2001. In that line of decisions, known as Suffolk I-IV, FERC said section 212(h) grandfathered classes of customers, not individual customers at specific delivery points.

“The Commission’s orders and opinions … support San Francisco’s argument that grandfathering applies to the class of customers that was eligible to receive wholesale distribution service on October 24, 1992, regardless of where in the city those customers may be located now or in the future,” the ALJ wrote. The judge defined the “class” of customers in the case as all “municipal public purpose load” in San Francisco.

PG&E, in contrast, contended that only “points of delivery” that existed prior to Oct. 24, 1992, could be grandfathered under its WDT. Customers that had relocated since that time were ineligible, it said.

FERC Overturned

In a November 2019 order, FERC disagreed with the ALJ’s decision. It found the Suffolk precedent inapplicable and said PG&E had not unreasonably denied service to some of San Francisco’s end users.

“The commission explained that San Francisco’s ‘class of customer’ approach would entitle all municipal public purpose load as designated by San Francisco that was eligible to receive wholesale distribution service on October 24, 1992,” FERC explained in Thursday’s order. “Ultimately, the commission concluded … that PG&E’s point of delivery approach to determining which San Francisco customers qualify for service under the WDT was just.”

The D.C. Circuit Court of Appeals reversed FERC’s decision in January 2022. It found that FERC’s interpretation of section 212(h) and PG&E’s tariff were too narrow, and its “attempts to defend its interpretation [were] unpersuasive.”

“That the tariff references ‘points of delivery’ does not necessarily imply that only specific points of delivery may be grandfathered, and those references to ‘points of delivery’ do not change the fact that the tariff expressly references the criteria of Section 212(h)(2),” it said.

The court criticized FERC’s orders in the case as demonstrating a “troubling pattern of inattentiveness to potential anticompetitive effects of PG&E’s administration of its open-access tariff.” Faced with claims that PG&E was refusing service to San Francisco customers, FERC “fell short of meeting its duty to ensure that rules or practices affecting wholesale rates are just and reasonable,” it said.

The appeals court sent the case back to FERC on remand. (See San Francisco Wins Against PG&E, FERC in DC Circuit.)

FERC issued a new decision in October that followed the court’s direction and agreed with San Francisco that its precedent did not limit grandfathering to a fixed location.

“The commission concluded that San Francisco’s loads within the customer classes served on October 24, 1992, are entitled to grandfathered service under the WDT, granted the complaint filed by San Francisco, and directed PG&E to submit revised WDT provisions,” FERC noted Thursday.

PG&E requested a rehearing.

PG&E Denied

In its request, “PG&E argues that the commission in the order on remand exceeded [its] authority in FPA section 212(h),” FERC noted. “PG&E urges the commission to set aside Suffolk County because, according to PG&E, the Suffolk County customer-class approach to grandfathering is inconsistent with the plain language of the statute, the intent of the statute in its legislative history, and the concept of grandfathering.”

PG&E also contended that “even assuming Suffolk County is valid and applicable precedent, the commission in the order on remand failed to address the potential for harmonizing PG&E’s proposed delivery-point methodology with the Suffolk County customer-class approach.”

FERC rejected PG&E’s arguments.

“PG&E asserts that the ‘customer-class approach’ can be reconciled with grandfathering based on points of delivery to provide service to a specific type of customer within a defined service area, because limiting grandfathering eligibility does not conflict with the text or intent of section 212(h),” FERC said.

But “in the order on remand, and as further discussed here, the commission has defined a coherent class of San Francisco customers eligible for grandfathering,” FERC said. “As the D.C. Circuit explained, the WDT ‘allows grandfathering of a customer San Francisco served under the prior interconnection agreement even though the customer seeks [WDT] service at a new delivery point.’

“Consistent with Suffolk County, eligibility under FPA section 212(h) therefore extends not only to the customers who were actually receiving service on October 24, 1992, but also to all subsequently interconnected customers of the same class.”

Second Case

In its January 2022 decision, cited above, the D.C. Circuit reversed FERC in a second case involving PG&E’s provision of distribution service in San Francisco.

In that case, the city and county contested PG&E’s refusal to provide lower-voltage secondary service to many sites within the city. PG&E instead offered to connect higher-voltage primary service, which requires the installation of transformers and carries higher fixed costs for ratepayers.

The city argued that the practice violated PG&E’s WDT.

The court remanded the matter back to FERC after overturning the commission’s unanimous 2020 decision rejecting San Francisco’s complaint.

In December, FERC ordered settlement judge procedures for the then three-year-old dispute. (See Settlement Hearing Ordered for PG&E, SF Distribution Dispute.)

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New York PSC Approves 20% Installed Reserve Margin

The New York Public Service Commission on Thursday approved a slight increase to the amount of reserve resources that load-serving entities must have available for the upcoming capability year (07-E-0088).

The New York State Reliability Council (NYSRC) had in December proposed raising the installed reserve margin from 19.6% to 20% for the 2023/24 capability year, which begins May 1 (05-E-1180). The figure equates to an installed capacity requirement of 120% of forecasted peak load for the year.

The council told the PSC it based its decision on the addition of 549.3 MW of wind generation and the need to maintain 350 MW of operating reserves during load shedding. It calculated the figure using the GE MARS system to examine factors such as demand uncertainty and scheduled or forced outages to establish a value above forecasted peak such that the loss-of-load expectation from resource deficiencies is fewer than 0.1 event days per year on average.

NYISO supported the proposal, as its own analyses yielded an IRM of 19.9%; 20% was “within a range of reasonable IRM levels that will maintain reliability.”

The PSC also said that the adopted IRM will “not have a significant adverse impact on the environment.”

The NYSRC will re-evaluate the IRM before the end of the year and submit another value should conditions change.

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PJM MRC/MC Preview: March 22, 2023

Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings Wednesday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

Markets and Reliability Committee

Consent Agenda (9:05-9:10)

The committee will be asked to endorse as part of its consent agenda:

B. proposed revisions to Manual 12: Balancing Operations resulting from the manual’s periodic review;

C. proposed revisions to Manual 14C: Generation and Transmission Interconnection Facility Construction; and

D. proposed revisions to Manual 37: Reliability Coordination.

Endorsements (9:10-9:50)

1. Periodic Review of Default CONE and ACR Values (9:10-9:30)

PJM’s Skyler Marzewski will review the proposed default cost of new entry (CONE) and avoidable-cost rate (ACR) values resulting from the Quadrennial Review. The values for most resource types would rise under the proposal, largely from changes to investment tax credits under the Inflation Reduction Act and to the reference resources for some classes, based on last month’s first read. (See “Updated Default CONE and ACR Figures,” PJM MRC/MC Briefs: Feb. 23, 2023.) The committee will be asked to give an advisory vote on the values, as well as corresponding tariff revisions.

Issue Tracking: Periodic Review of Default CONE and ACR Values

2. Manual 11 Revisions (9:30-9:50)

PJM’s Joseph Tutino will review proposed revisions to Manual 11: Energy and Ancillary Services Market Operations, and the committee will be asked to endorse them.

Members Committee

Endorsements (11:10-11:30)

1. Periodic Review of Default CONE and ACR Values (11:10-11:30)

Marzewski will again review the proposed default CONE and ACR values, and the committee will be asked to give an advisory vote on the values and tariff revisions.

If approved by both committees, PJM anticipates filing the changes with FERC by the end of the first quarter with an effective date in November.

Issue Tracking: Periodic Review of Default CONE and ACR Values

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FERC Issues Show-cause Order on ComEd Formula Rate Protocols

FERC last week ordered show-cause proceedings for Commonwealth Edison’s (NASDAQ:EXC) formula rate protocols, saying that they may not provide adequate transparency and lack a proper framework for challenging rates (EL23-31).

The commission found ComEd’s protocols deficient in that they do not specify who can request information from transmission owners and what has to be provided in response, holding the utility to standards imposed by a 2012 order on MISO’s protocols. The commission has since opened proceedings on formula rate protocols regularly, seeking to ensure they are compliant with the provisions laid out in the MISO order. (See related story, PSCo, Idaho Power Comply with Show-cause Order.)

FERC said ComEd may not be meeting several of the disclosures the MISO order requires, including accounting practices for items where the commission hasn’t provided specific direction, changes in tax elections and correcting of errors and prior date adjustments. It also said there does not appear to be adequate detail on various types of costs, requirements on documents requests, and the identification of transactions related to mergers and how they may affect formula rates.

The MISO order also requires that the updated filing with FERC must follow an informational exchange period with interested parties, but the commission said ComEd’s protocols may not require an adequate time frame. The utility’s definition of which parties can participate in the review process may also be insufficient by not providing enough clarity.

The provisions for challenging formula rates may also be inadequate, FERC said, by not containing enough information about which parties can informally challenge the proposed inputs and how that challenge can be converted to a formal challenge with the commission if a resolution cannot be found. The order also says that the protocols do not contain enough clarity that such challenges are pursuant to the protocols themselves, rather than rule 206 of its Rules of Practice and Procedure.

ComEd has 60 days to respond to the order to either defend its protocols by showing how they comply with the commission’s requirements or to detail the changes it believes would be necessary to address the issues laid out in the order. Comments will be accepted within 21 days of the utility’s response to address whether the rates are just and reasonable or to suggest possible changes.

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ITC Defends ROFR Use for Major Tx Buildout

ITC Holdings (NYSE:ITC) says that a MISO 2016 market efficiency project is proof that rights-of-first-refusal laws benefit the grid and ratepayers.

Nathan Benedict, ITC’s regulatory strategy manager, said the transmission developer is so confident that the 50-mile, 345-kV line in Minnesota has been so successful that it will use the project as a case study when it files comments on transmission planning and cost containment with FERC later this week.

The $118 million Huntley-Wilmarth line was part of MISO’s 2016 Transmission Expansion Plan and would have been open to competitive bidding were it not for Minnesota’s more than decade-old ROFR law.

A handful of state legislatures in MISO’s footprint have introduced and sometimes tabled ROFR rules this year. The pressure to pass or set aside the laws is sharpened by the nearly $30 billion in new transmission spending the grid operator may recommend for its Midwest region under its long-range transmission plan (LRTP). Mississippi became the latest MISO state to enact a ROFR law when Gov. Tate Reeves signed legislation earlier this month.

Meanwhile, a pending complaint asks FERC to invalidate states’ ability to give incumbent utilities first shots on construction. (See MISO States Ramp Up ROFR Legislation.)

“It takes this discussion of who is going to build the transmission off the table and focuses on the transmission planning,” Benedict told RTO Insider. “We realize the most cost-effective measure to cost containment is coordinated transmission planning.”

“We feel at the end of the day, the Minnesota ROFR allowed us to manage costs effectively and respond to route, environmental and landowner concerns and secure a return on investment,” ITC Midwest Communications Manager Rod Pritchard said.

Pritchard said Huntley-Wilmarth was originally estimated at $108 million in 2016 dollars. He said the original design incorporated a single-circuit, H-frame wooden structure design that ultimately morphed into the costlier double-circuit, steel monopole design after input from the Minnesota Public Utilities Commission.

Possible routing changes meant project co-owners ITC Midwest and Xcel Energy (NASDAQ:XEL) were grappling with nine different route alternatives ranging from 45 to 57 miles that differed from MISO’s preliminary estimates, Pritchard said. At one point, landowner feedback collected by the Minnesota PUC could have pushed the line’s cost as high as $167 million.

Pritchard said that because of “collaboration with incumbent utilities and very aggressive cost-containment measures,” ITC and Xcel were able keep costs at $118.3 million. He called Huntley-Wilmarth an “excellent example of two transmission owners under the ROFR process working together” to provide the best routing and cost-containment decisions.

Huntley-Wilmarth is now alleviating constraints in southern Minnesota and northern Iowa, once one of MISO’s most congested spots, Pritchard said.

“There are segments of our industries where competition doesn’t make sense,” Benedict said, pointing to a 2022 Concentric Energy Advisors’ report that concluded competitive projects average 27% in cost increases and an additional 12 months of schedule delays.

Benedict said there’s no time to waste in energizing the new transmission necessary to bring record amounts of renewable energy online.

ITC estimates it will be responsible for roughly $1.4 billion to $1.8 billion of MISO’s first LRTP portfolio, which is valued at $10 billion. The developer will be involved in six of the 18 projects.

“As an incumbent, we have extensive knowledge of the communities, the geography … the intricacies of what it takes to plan transmission,” Benedict said.

He said states have the “prerogative” to remove the uncertainty from transmission-expansion decisions after FERC issued Order 1000 in 2011.

Benedict acknowledged that ITC differs from other utilities in that it’s an independent and unbundled transmission developer. He said the company’s independence from generation means it’s focused on how to best improve the transmission system.

“We really want an efficient grid that works best for customers,” he said.

Benedict said while transmission investment raises customer bills, it can also offset delivered energy costs and other portions of the bill.

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Texas Court Reverses PUC’s Uri Market Orders

A Texas appeals court on Friday reversed the Public Utility Commission’s orders to keep ERCOT wholesale prices at the $9,000/MWh cap during the deadly February 2021 winter storm, adding even more uncertainty to a market facing a yet-to-be determined redesign.

A three-judge panel for the 3rd Court of Appeals in Austin ruled that the PUC exceeded its authority by setting prices at their limit for four days during the storm. The commission said that the move was necessary to incent generation to stay online as ERCOT worked desperately to bring the grid back to life after it came within minutes of a total collapse. (See Texas PUC Won’t Reprice $16B Error.)

The court said the commission’s actions “entirely” eliminated competition, contrary to state law.

“Setting a single price at the rule-based maximum price violated the Legislature’s requirement in the Utilities Code … that the commission use competitive methods to the greatest extent feasible and impose the least impact on competition,” Justice Edward Smith wrote (03-21-00098-CV).

The court reversed two PUC orders responding to market transactions clearing as low as $1,200/MWh (51617) and remanded the case for “further proceedings consistent” with its ruling. Whether that takes place at the PUC or in another arena remains to be seen.

The PUC said it doesn’t comment on pending litigation. Neither does ERCOT.

The appeal was filed by Luminant (NYSE:VST), Vistra’s generating subsidiary, shortly after the 2021 storm, also known as Winter Storm Uri, knocked about 50 GW of generation offline. More than 200 Texans died during the resulting dayslong outages.

Other energy companies intervened on both sides of the case.

“We agree with the decision today by the Court of Appeals in Austin, but this is an ongoing legal proceeding, and we cannot predict the final outcome,” Luminant spokesperson Meranda Cohn said in an emailed statement.

Luminant argued before the court last year that the PUC’s actions addressing the power shortage were “invalid and ineffective” and “wreaked havoc.” The PUC told the court that the appellants were upset over their financial losses and were asking the judges to “second-guess” decisions made by the PUC and ERCOT under extreme weather conditions.

The actions resulted in $16 billion of market transactions that ERCOT’s Independent Market Monitor said were incorrectly priced during 33 hours after ERCOT stopped shedding firm load. The PUC declined the reprice the transactions. (See “Monitor: $16B ERCOT Overcharge,” ERCOT Board Cuts Ties with Magness.)

Katie Coleman 2017-03-01 (RTO Insider LLC) FI.jpgKatie Coleman, O’Melveny & Myers | © RTO Insider LLC

Attorney Katie Coleman, whose law firm represents several market participants, pointed out that some of the balance during the storm has since been securitized and that some participants are paying off debt that they now might not even owe. Other transactions settled outside ERCOT can’t really be undone, she said.

“Resettling just the real-time and day-ahead markets creates chaos and undermines positions from two years ago,” Coleman said. “It’s a giant mess. I don’t know how they can even try to unscramble that egg.”

Austin-based energy consultant Alison Silverstein, who was part of FERC’s decade-plus work settling the 2001 California market implosion, used a different metaphor in agreeing with Coleman.

“Practically speaking, it will be challenging to unwind the daisy chains of electricity transactions from that week, figure out what the prices should have been and claw the overpayments back,” she said. “This could be harder for Uri transactions because a lot of that money paid for wildly inflated natural gas, rather than increasing many generators’ profits. It’s unlikely that the PUC can claw back Uri profits from businesses it doesn’t regulate.”

The court is aware of those same issues. “Our decision in this appeal may have very real material consequences for all involved,” Smith said in his opinion.

But Silverstein agreed with the court’s decision, finding it ironic that the ruling found that the PUC exceeded its authority by “eliminating competition entirely.” She pointed to Smith’s use of direct quotes from Texas statutes regarding “electric services and their prices should be determined by customer choices and the normal forces of competition” and that regulatory authorities should use “competitive rather than regulatory methods … to the greatest extent feasible” and with “the least impact on competition.”

“For the past year and at present, the Texas commission and legislators are considering a number of electric market options and policies that would advance regulatory methods that stifle customer choices and choke competition,” Silverstein said. “This order should remind us that since 1995, Texas legislators and policymakers have repeatedly supported free-market competition for electricity. We should find ways to fix our current reliability and affordability challenges by leveraging competition, not squashing it.”