FERC has accepted SPP tariff revisions that allow make-whole payments for incremental energy costs affected by incremental energy offer caps under Order 831, regardless of the resource’s reason for commitment.
The commission said in a Sept. 19 order that the revisions provide an opportunity for cost recovery, ensuring the resources have an opportunity to recover their incremental energy costs, and an incentive to provide accurate operating parameters and to follow dispatch instructions during Order 831 conditions (ER24-2570).
The revisions are effective Oct. 16.
FERC’s Order 831 revised regulations to address incremental energy offer caps by requiring each commission-jurisdictional grid operator to: cap incremental energy offers at the higher of $1,000/MWh or that resource’s verified cost-based incremental energy offer; and cap verified cost-based incremental energy offers at $2,000/MWh when calculating LMPs.
SPP uses energy offers between $1,000 and $2,000/MWh to set the LMP, but its Market Monitoring Unit must verify the offers in advance. The MMU verifies whether energy offers above $1,000/MWh reasonably reflect the resource’s actual or expected costs prior to calculating LMPs.
The Monitor told FERC it supported SPP’s proposal, contending there are gaps in the make-whole payment construct that could impede generator owners from receiving full reimbursements under Order 831. It said the gaps could incentivize generators to reduce their financial risks, which could harm the market during extreme conditions.
FERC has dismissed a complaint the Virginia Municipal Electric Association (VMEA) filed against Dominion Energy’s Virginia Electric Power Co. (VEPCO) alleging the utility overcharged its members $2.8 million (EL24-99).
The commission declined to assert primary jurisdiction over the dispute, which it can do at its own discretion.
VMEA is a wholesale customer of Dominion’s utility, and it argued the improper charges were related to the Regional Greenhouse Gas Initiative. VMEA has a full requirements electric service contract with VEPCO, with includes charges based on a formula rate that includes the Uniform System of Accounts, Account 509, as an input.
VEPCO exceeded the RGGI cap in 2021 and 2022, requiring it to spend $137.7 million and $123.5 million in emissions allowances. The utility recovered $84.2 million of that under a rider the State Corporation Commission (SCC) approved.
The rest of the money, $177.1 million, initially was supposed to be recovered in VEPCO’s 2023 biennial rate review, but VMEA said the utility told state regulators that amount would be “deemed recovered” and would not be recovered in future rates.
VMEA claimed the $177.1 million should not have been included in Account 509. It was, and that led to the claim of being overcharged $2.8 million. The association wanted FERC to order Dominion to implement its formula rate without those charges in the account.
Virginia Power told FERC the SCC never disallowed recovery of the RGGI costs, and they were properly included in the rates charged to its retail customers and wholesale customers like VMEA.
The utility initially recovered RGGI costs through the rider, but it got rid of that once Gov. Glenn Youngkin (R) decided to withdraw from the multistate carbon market that had been entered into under his predecessors.
The SCC allowed VEPCO to recover the $177.1 million in its base generation rates in a June 2022 ruling, the utility told FERC. Its deal with VMEA also allows the utility to recover RGGI costs related to its service.
In declining jurisdiction over the dispute, FERC said it did not have expertise compared to the SCC or a state court to adjudicate the dispute. The issue also does not require any uniformity of interpretation for FERC because the facts are unique to the dispute and the complaint also does not raise any broader policy issues relevant to FERC’s jurisdiction.
“Resolution of this matter does not require the commission to interpret its accounting rules and regulations; rather, the dispute concerns the factual issues related to the specific terms of the agreement and the SCC’s decisions in a series of retail ratemaking orders and proceedings,” FERC said Sept. 19.
Commissioner Mark Christie, who chaired the SCC before taking his position at FERC in January 2021, did not participate in the case.
INDIANAPOLIS — MISO said it managed a milder summer overall compared to previous years, though it weathered two hurricanes and escalated into emergency warnings during a heat wave.
MISO served its summertime peak of 122 GW on Aug. 26, using two maximum generation warnings as the Midwest baked under a prolonged heat wave. (See Late August Heat Wave Delivers 122-GW MISO Summer Peak.) Otherwise, summer brought an 85-GW average load, closely following the average load of the three previous summers.
MISO’s average $28/MWh real-time price throughout the season tracked cheap, $2/MMBtu coal and gas prices. The RTO experienced about 31 GW of daily generation outages and derates, lower than in previous years.
At a Sept. 17 Markets Committee of the MISO Board of Directors, Independent Market Monitor David Patton said MISO’s summer peak would have been about 1.8 GW higher without voluntary demand response in the footprint.
“It’s hard to believe it’s been a while since we’ve been here, about three years,” Executive Director of System Operations Jessica Lucas said about delivering a hurricane operations post mortem. She said MISO prepared for an above-normal hurricane season, but so far, storms have been scarce.
Lucas said the Category 1 Beryl nevertheless caused the loss of 73 MISO-operated lines and 250,000 customer outages, a “surprising” number for a “low-intensity” storm.
MISO reported all but one of the lines leading to a Southeast Texas load pocket knocked out of commission. Eventually, the remaining in-service line — a tie line with SPP — went down as well July 8. Prior to the final outage, MISO noticed more generation available in the load pocket than load to serve, leading it to direct all but one generator offline. MISO kept flows on the line at essentially zero to limit potential customer impacts. MISO was prescient to do so, Lucas said, because that remaining line eventually went out of service.
Lucas said she had the “privilege” of being in MISO’s Little Rock, Ark., control room during the night to see firsthand how MISO, SPP and Entergy coordinated to resync the area to the bulk electric system.
“Operating an island for over eight hours is quite a trick. One of my colleagues said it’s like spinning a plate on a needle,” Vice President of Operations Renuka Chatterjee said.
MISO Director Trip Doggett said the feat was the result of “heroic effort.”
“I thought MISO did an amazing job of managing reliability during this event,” Patton said. However, Patton added that southeastern Texas “by far” experiences the most load shedding in MISO.
Patton suggested that MISO “take a hard look at its capacity zones” and consider splitting up MISO’s Zone 9, which contains Louisiana and southeastern Texas. He said the large zone and Louisiana’s capacity-sufficient status mask the fact that southeastern Texas needs resources.
“It prevents the market from signaling that MISO needs to build more generation in this area,” Patton said of the size of the zone.
MISO South’s second hurricane over summer proved more uneventful, Lucas said.
MISO declared conservative operations Sept. 10-13 for its South region as Hurricane Francine made landfall in Terrebonne Parish on Sept. 11 with Category 2 force. At the time, Entergy reported upward of 300,000 customer outages. By Sept. 16, Entergy reported it restored nearly all customers in Louisiana and Mississippi.
“There was not nearly as much excitement as Beryl caused,” Lucas said.
Lucas also noted operators navigated a “wind drought” lasting 11 hours July 21 and eight hours July 22 among its 31-GW wind fleet.
MISO defines wind droughts as periods during which wind output dies down to 500 MW or less for five or more hours. MISO said it has experienced 11 such events since 2020.
“As more weather-dependent resources are added to the portfolio, managing long-term, multiday resource droughts will be a challenge,” Lucas said.
IMM Demands Tougher Demand Response Requirements
Despite summer 2024’s lack of emergencies, Patton used his time slot for a summertime review to ask MISO to “beef up” testing to make sure load-modifying resources can deliver what they promise.
“So much of what we pay for demand response resources has turned out to be manipulative, or not useful to the system,” Patton said.
Patton said a review of MISO’s demand response showed that up to 25% of DR resources submit “mock tests” for their accreditation in lieu of real testing, which presents opportunities for fraudulent data submissions.
Patton said the review also uncovered one commercial retail end-use customer signed up with multiple market participants for the same load and some “unconsummated contracts with critical information redacted that prevent MISO verifying the DR amount or validity.”
Patton also said MISO should stop allowing load-modifying resources to cross-register as both capacity resources and emergency demand response. He said resources should commit to selling one or other, or better yet, MISO should eliminate its emergency demand response program. He pointed out MISO never actually has called on emergency demand response.
Patton’s suggestions come after multiple demand response resources in MISO have been disciplined for deceptive behavior.
Over the past two years, FERC has caught three companies manipulating MISO’s demand response market and collecting unwarranted payments. The commission found that an air separation facility in Indiana accepted payments for fictitious load reductions, an Arkansas steel mill made phony use reductions spanning years, and that an obscure, Texas-based LLC formed to sell in-car ketchup holders fraudulently enrolled customers and made bogus DR offers in three capacity auctions. (See FERC Catches Ketchup Caddy Co. in Another Fake DR Scheme in MISO.)
INDIANAPOLIS — At their quarterly meetup, MISO members largely agreed there won’t be an easy path to achieving decarbonization affordably for customers.
“We’ve gone from talking about rates, to talking about energy burden to now talking about energy wallet,” Sarah Freeman said, introducing members’ chosen topic, “Affordability, Sustainability and Reliability,” at a Sept. 18 meeting of MISO’s Advisory Committee.
“I really don’t think we’re prepared for what the transition is going to cost in the next five to 10 to 15 years,” said Michelle Bloodworth of coal advocate America’s Power. Bloodworth said customers of rural power cooperatives will be particularly hard hit.
Arkansas Public Service Commission consultant Keith Berry said affordability is a chief issue in MISO South, which he said contains some of the poorest residents in the nation. He said he worries what MISO’s third long-range transmission plan (LRTP) portfolio — which will focus on MISO South — may do to customer bills.
“We look with some trepidation on what the costs of Tranche 3 might be,” Barry said.
The Union of Concerned Scientists’ Sam Gomberg said MISO’s Environmental Sector views the three words as interconnected.
“If electricity is cheap, but it’s fouling your waters and making our planet uninhabitable, then it’s not affordable,” Gomberg said.
Clean Grid Alliance’s David Sapper said to further all three, MISO should “unlock the queue without resorting to a queue cap,” finding ways to bring new resources online quickly.
“Resource expansion is the cornerstone of competition, so we need to get the queue moving,” Sapper said. He also said MISO’s transmission owners should use grid-enhancing technologies and dynamic line ratings to leverage the most they can from the existing system and host the greatest number of new megawatts.
Other members said some transmission projects will be better than others at delivering value.
Yvonne Cappel-Vickery, of the Alliance for Affordable Energy, said the industry should work to put a stop to inefficient transmission “overbuilds that starve the regional transmission planning process.”
Cappel-Vickery said some utilities “flock” to new power plants and expensive local lines that come “at the expense of bringing lower-cost resources” to their territories. She said the problem is particularly pronounced among utilities that own transmission and generation.
LS Power’s Sharon Segner also said comprehensive, regional planning needs to trump the local projects that are ubiquitous in MISO’s annual transmission planning.
Gomberg said members must ask themselves if they’re willing to bear near-term costs for long-term benefits.
“If we underbuild, we’re going to leave benefits on the table and risk affordability, sustainability and reliability,” he said, adding that regional transmission needs to be “smart and targeted.”
ITC’s Brian Drumm said there’s no substitute for transmission to achieve all three objectives. He said there’s current evidence that MISO and members have been underbuilding for years.
Iowa Utilities Board Member Josh Byrnes agreed the system to date has been underbuilt.
Multiple stakeholders said bills are opaque and confusing for customers and said some efforts from the industry to help ratepayers understand what’s in their bill could go far.
Gomberg called for a greater commitment to transparency from utilities and MISO but added the simple fact is shareholder-beholden utilities exist to make money.
Gomberg said utilities may include “line items for things that they don’t want to pay for” in customer bills, “chip away at regulatory oversight” and approach state commissions with “inflated costs” in rate cases.
“That’s just the world we live in,” he said, qualifying that he wasn’t taking a shot at capitalism.
In a separate discussion on the state of MISO’s seams, Sustainable FERC Project’s Natalie McIntire said MISO ought to do more to build cross-border transmission.
“As the energy transition occurs and more and more renewables are added to the system and weather events get more extreme, the ability to share across our seams is going to be more important,” she said.
McIntire said MISO so far has provided “very little to no” insights into the scope of their recently announced interregional transfer capability studies with PJM and SPP.
On the other hand, the Coalition of Midwest Power Producers’ Travis Stewart said MISO might need to reevaluate “the amount that we lean on our neighbors.”
Stewart said with PJM anticipating supply shortfalls, MISO soon won’t be able to rely on the few gigawatts it receives daily from its eastern neighbor.
“Those megawatts are going away,” Stewart warned, saying MISO would be well-served by internally becoming resource and energy adequate so neighbors can begin to lean on MISO.
Vice President of System Planning Aubrey Johnson said seams projects might have been inhibited thus far because other RTOs haven’t been as interested in scenario-based long-range transmission planning as MISO has been.
“Ultimately, I do think there’s an attitude of ‘solve your own problems first,’” Johnson said. He added that MISO’s neighbors’ interest in interregional projects might grow after they approve their own major portfolios.
“I think Order 1920 is going to bring the other regions along,” Drumm agreed.
The Western Interconnection reached a record-breaking peak load July 10 despite relatively moderate demand in CAISO, the ISO said during a Sept. 18 meeting of its Market Performance and Planning Forum.
“When you look holistically across the West, it happens to be the warmest July on record, and that really drove the high loads in the Western Interconnection,” Guillermo Bautista Alderete, director of market analysis and forecasting at CAISO, said.
The Western grid’s peak reached 167,988 MW, slightly higher than the previous record in 2022. July saw many hours with high demand, Alderete said, and so the peak wasn’t necessarily an outlier for the month.
Despite record-breaking conditions across the West, temperatures in the CAISO system where the demand was concentrated were “not that extreme,” keeping ISO loads moderate, with a peak of about 45,000 MW — well below the historical peak of 52,000 MW.
“At the end of the day, it is not only how high the demand is, but also how well-equipped we are to handle that level of demand,” Alderete said.
‘Substantial Volumes of Exports’
Favorable resource adequacy conditions in CAISO helped support high loads in the West.
“We need to have enough resource adequacy capacity to be able to meet our actual load plus our reliability obligation. … When you put that obligation together and compare that against the resource adequacy capacity that we have available, you can see we were within a healthy margin,” Alderete said. “We were never even really close to hitting the resource adequacy showing level, and that means that the levels of demand that we have in the system were moderate enough that the resource adequacy capacity was sufficient to meet that obligation.”
CAISO experienced a marginal increase in RA capacity from 2023 to 2024, a trend the ISO expects will continue over time. Given the moderate levels of demand in the ISO’s balancing authority area in July, and even on the most critical days of July 23-25, RA capacity was enough to meet the load obligation.
CAISO’s prices increased as expected in July, reaching peaks on July 24. In June, average prices were typically below $50/MWh, while in July, they rose to $200/MWh for hours ending 7 and 8 p.m. Prices in the Pacific Northwest remained low compared with California and the Desert Southwest.
“Practically speaking, even those prices are moderate given all the conditions that we have when we look at the real-time,” Alderete said.
Import and export levels were close to historical norms as well. Most imports with self-schedules or bids at or below $0/MWh were cleared in both the day-ahead and real-time markets, though up to 640 MW of bid-in RA couldn’t clear given path derates on the Malin intertie because of the impact of the Park Fire.
CAISO cleared “substantial volumes of exports” in July due to conditions driven by record loads across the Western Interconnection, resulting in several days of net exports.
While the ISO had to reduce exports on very few days, its hour-ahead scheduling process on July 24 reduced up to 900 MW of exports.
The Western Energy Imbalance Market (WEIM) provided operational benefits and offset risk for members by facilitating assistance energy transfers (AETs), which allow a participating BA to receive energy when it does not meet the market’s resource sufficiency requirements ahead of a trading interval. Ten WEIM balancing areas opted into the AET program in July, the largest rate of participation since the program’s inception, Alderete said.
The ISO in July also identified three issues related to the Residual Unit Commitment (RUC) process and incorrect reporting of exports.
“I would say, in the grand scheme of things, they are relatively minor items, but we want to provide the transparency,” Alderete said.
On July 4, the RUC process triggered undersupply infeasibility — which indicates a potential supply shortage — without attempting to reduce low-priority exports to maintain supply, but the issue was fixed the following day.
The month also saw an incorrect reporting of export reductions in the customer portal that was fixed July 9, as well as an incorrect loss of high-priority status for certain exports. In particular, under different permutations of bidding in day-ahead and real-time markets, different bid validation rules triggered the unintended loss.
CAISO is assessing whether to revise the validation rules and has resolved all other issues, Alderete said.
WASHINGTON — FERC said it will work with federally recognized tribes on whether it needs to issue a new rulemaking to address their issues interconnecting renewable resources to the grid.
The announcement at the commission’s Sept. 19 open meeting comes just over a month after the Alliance for Tribal Clean Energy filed a petition for an expedited rulemaking on the subject, arguing the few tribes able to build major generation projects face unique issues in hooking them up to the grid (RM24-9).
“This will be the first time that the commission engages in tribal consultation on an electric markets issue,” FERC Chair Willie Phillips said at the meeting. “Improving the commission’s tribal engagement and consultation practices is one of my top priorities and a commitment that’s reflected in our equity action plan.”
FERC is offering all its staff a training opportunity with Maranda Compton, an expert on tribal legal issues and a citizen of the Delaware Tribe of Indians, Phillips said.
The alliance argued that some FERC standard rules, such as commercial-readiness deposit requirements and withdrawal penalties, do not make sense with its members’ projects.
“Tribal projects that advance to the point of seeking interconnection are not speculative,” the tribes said. “They are not undertaken to take a big risk in hopes of making a big profit. They are not motivated to take advantage of fluctuations in the market. They are pursued to self-serve tribal needs for electricity to advance the goals of lower electricity rates, revenue for tribal governments, tribal economic development and tribal self-sufficiency.”
Tribal lands are home to some of the best energy resources in the country, but on average, they pay some of the highest energy rates, with 56% paying more than double the national average, they said.
“While tribal nations are eager — indeed, desperate — to change their economic predicament and energy circumstances, they find themselves stymied by unworkable and unduly burdensome rules that fail to account for tribal nations’ unique organizational structures and funding constraints,” they said.
Building utility-scale generation projects can help redress tribal poverty and energy inequity through economic development, creating revenue and jobs, and promoting self-sufficiency, they wrote. They asked FERC to adopt limited and narrowly tailored commercial-readiness and withdrawal penalty rules that reflect their financial barriers, such as not being able to take out loans on land they hold in common among all their citizens.
The issue also came up at the recent technical conference on interconnection, during which the Oceti Sakowin Power Authority’s general counsel, Jonathan Canis, described the difficulties in trying to get a major project connected to the grid.
The power authority is jointly owned by seven Sioux tribes and is trying to build two wind farms in western South Dakota, which is a high-voltage transmission “desert,” Canis said. Interconnection studies would have the authority pay $250 million for the transmission on its own.
“Of course, that made our projects economically infeasible,” Canis said. “To put it in perspective, our entire estimated budget for development and construction for two wind farms is $1.1 billion, so this increased our total project cost by 20 to 25%. We had to withdraw from the queue, and our projects are now on hold. We’re focused 100% on how to get back in there and how to make it affordable.”
The authority worked with the Western Area Power Administration and Basin Electric Power Cooperative to develop a transmission solution, a 700-mile 345-kV project that would cross Sioux land. But only parts of it were picked by SPP for the regional transmission plan, and those do not touch tribal lands, Canis said.
The Department of Energy’s Loan Programs Office also has the funding for tribal energy projects, but that has never been used, outside of one commitment of $74 million for a solar microgrid to serve a big casino, Canis said.
“We’re going to ask Congress to repurpose that fund to another DOE office that will really put that money to work,” Canis said. “And to put it in perspective, there’s only about five tribal development companies in the country, and there are not that many tribes with enough land area to develop their own wind farms. So, a fraction of that $20 billion could fix all our problems.”
A proposed update to WECC’s long-term strategy has sparked a debate over whether the organization should describe itself as “The Voice of Reliability in the West.”
The phrase figures prominently in a draft of the long-term strategy, which was discussed by WECC’s Board of Directors on Sept. 17 and during its annual member meeting Sept. 18.
WECC decided to update the strategy in part because the Western Interconnection is changing “at a magnitude and pace that is unparallelled,” the draft document said. The current version of the strategy was adopted in 2020. (See WECC Board Approves New Chair, Long-term Strategy.)
“Even in the last year, new things are coming into focus,” General Counsel Jeff Droubay told the board. “Large loads, as an example, brought about by data centers, AI, crypto mining. We’re seeing these loads come online in an unprecedented way.”
The draft strategy lists five “impact areas” that largely are focused on reliability.
“Our holistic risk-based approach uses all the tools and skills available to deliver comprehensive risk mitigation strategies,” the document states under Impact Area 1.
But during the member meeting, some members questioned the strategy’s statement that WECC is “uniquely positioned to be The Voice of Reliability in the West.”
Pat O’Connell, chair of the New Mexico Public Regulation Commission, said the term “the voice” was “a little too heavy-handed.”
O’Connell noted that he’s deeply involved in reliability in New Mexico in his work as a regulator. And groups participating in the Western Resource Adequacy Program (WRAP) also are playing a role in reliability, he said.
“There is no one of us in charge of the whole thing,” O’Connell said.
Others at the meeting suggested alternative wording such as “a critical voice for reliability” or “a strong voice leading the pursuit of interconnection reliability.”
WECC member Grace Anderson from the California Energy Commission said the strategy should further emphasize WECC’s interconnection-wide work. She said reliability of the Western Interconnection is different from distribution reliability, for example.
During the board meeting, WECC board member Felicia Marcus said she likes that the strategy describes how WECC is viewed by others. For example, Impact Area 4 states that WECC’s “resource- and technology-neutral, interconnection-wide perspective is respected and trusted to assure decision-makers that they have an independent partner to rely on.”
But Anderson said the document left her unsure about WECC’s plan of action.
“To me, I think about a strategic plan, and it’s about what we’re going to do, how we’re going to prioritize,” Anderson said.
Responding to Anderson, Droubay said the plan is intended to work “hand-in-glove” with scorecards WECC uses to show whether initiatives are proceeding on schedule.
Another goal of WECC’s long-term strategy update is to align with a new strategy being developed by the ERO Enterprise, which consists of NERC and six regional entities including WECC.
The plan’s first area of focus is using “a broad range of data, tools and approaches” to address existing risks and prepare for emerging and unknown risks to the grid.
Other focus areas are maintaining cyber- and physical security programs; promoting stakeholder engagement; and performing as an “effective and efficient team.”
During the Sept. 17 meeting, WECC’s board voted to endorse the ERO Enterprise Long-term Strategy. NERC’s board is expected to vote on the strategy in December.
As for its own long-term strategy, WECC will accept feedback on the draft document through October. A final version of the document is expected to go to the WECC board for approval in December.
FERC on Sept. 19 indicated its approval of NERC’s new reliability standard requiring utilities to implement internal network security monitoring (INSM) on some grid-connected cyber assets, while also floating the prospect of new standards aimed at securing the supply chain of critical electronic components.
The commission issued two Notices of Proposed Rulemaking (NOPRs) at its monthly open meeting. The first indicated its plan to approve CIP-015-1 (Cybersecurity — INSM), which NERC submitted to FERC in June (RM24-7). It would require utilities to implement INSM at all high-impact grid-connected cyber systems, as well as medium-impact systems with external routable connectivity (ERC). (See NERC Submits INSM Standard for FERC Approval.)
FERC ordered NERC to develop requirements for INSM last year, calling the proposal a necessary response to events like the SolarWinds hack of 2020. In that attack, malicious actors — later identified by U.S. law enforcement as belonging to Russia’s Foreign Intelligence Service — infiltrated the update channel for SolarWinds’ Orion network management software and pushed code to customers that the attackers could use to gain access to their systems.
Commission staff said last year the compromise demonstrated a weakness of the kind of cybersecurity measures mandated in NERC’s Critical Infrastructure Protection (CIP) standards, which require a utility to monitor communications from the inside of its electronic security perimeter (ESP) — the electronic border around its internal network — to the outside. INSM could help security staff discover and respond to an attacker that already had infiltrated the system and did not need to communicate with external attackers, they said.
CIP-015-1 would require registered entities to “implement one or more documented process(es) for [INSM] of networks … of high-impact [grid] cyber systems and medium-impact … systems with” ERC. Documented processes under the standard must include:
network data feeds to monitor network activity, including connections, devices and network communications;
at least one method to detect anomalous network activity using the network data feeds; and
at least one method to evaluate anomalous activity to determine what additional action is needed.
Entities also would have to implement documented processes to retain INSM data associated with anomalous network activity and to protect all data gathered or retained to prevent unauthorized deletion or modification.
FERC’s NOPR proposed to accept CIP-015-1 but also described the standard in its current form as “not … fully responsive to the commission’s directive in Order 887 to implement INSM for the ‘CIP-networked environment.’” The commission specifically warned that the standard is not sufficient to “defend against attacks that circumvent network perimeter-based security controls.”
FERC said it’s concerned attackers may be able to compromise systems external to a utility’s ESP, such as electronic access control and monitoring systems (EACMS) or physical access control systems (PACS), and then use that control to establish access within the perimeter as a trusted communication.
To address this potential shortcoming, the commission proposed approving CIP-015-1 while directing NERC to develop additional modifications to the standard “that would extend INSM to include EACMS and PACS outside the” ESP. The ERO would need to submit the revised standard to the commission within 12 months of the effective date of FERC’s final rule. Comment on “all aspects of this proposal” is due to FERC 60 days after the NOPR’s publication in the Federal Register.
New Supply Chain Standards Proposed
FERC’s other NOPR proposed to direct NERC to address perceived gaps in the ERO’s standards concerning supply chain risk management (SCRM) (RM24-4). SCRM provisions are found in three existing standards:
“Although the currently effective SCRM reliability standards provide a baseline of protection against supply chain threats, there are increasing opportunities for attacks posed by the global supply chain,” FERC said in its NOPR. “Using the global supply chain, adversaries have inserted counterfeit and malicious software, tampered with hardware and enabled remote access.”
The gaps the commission identified in NERC’s standards relate to the sufficiency of entities’ SCRM plans as concern the identification, assessment and response to supply chain risks, as well as the applicability of the current standards to protected cyber assets. FERC said the current standards do not specify when and how entities should identify and assess supply chain risks; they also do not require entities to respond to supply chain risks through their SCRM plans.
These gaps have led to “multiple gaps in SCRM” observed by FERC staff during their audits of responsible entities’ CIP compliance in fiscal 2023. (See FERC Report Identifies CIP Audit Lessons Learned.) Staff identified multiple SCRM-related security risks among the seven audited entities, most notably a “lack of consistency and effectiveness in SCRM plans for evaluating vendors and their supplied equipment and software.” Auditors also said many entities’ SCRM plans did not have procedures for responding to identified risks.
FERC’s NOPR would have NERC submit new or modified standards establishing specific timing for entities to evaluate vendors and equipment to identify supply chain risks, along with periodic assessments of risks associated with vendors, products and services. The standards also would have to require entities to ensure their SCRM plans have steps to validate the accuracy and completeness of information received from vendors during the procurement process, and a process to document, track and respond to identified supply chain risks.
As with the INSM proposal, the commission invited interested parties to submit comments on its intended actions. Comments are due 60 days after the NOPR’s publication in the Federal Register.
Proponents of SPP’s Markets+ contend in their latest “issue alert” published Sept. 18 that the framework provides a much more equitable solution to tackling market seams than does CAISO’s Extended Day-Ahead Market (EDAM).
In an email to RTO Insider, Jeff Spires, director of power at Powerex, said seams in the West have “resulted in inequitable outcomes, shifting value and reliability risk between subregions, and these outcomes are largely not captured in available studies to date.” (See SPP Briefs: Week of Nov. 7, 2022.)
It’s a point that Powerex — the first and, so far, only entity to tentatively commit to joining Markets+ — has broached before. In March, the Canada-based energy trader issued a report criticizing CAISO’s operational practices in the Western Energy Imbalance Market (WEIM) during the January 2024 cold snap in the Northwest. The report argued CAISO’s processes unjustifiably limited energy transfers into the region during the weather event and squeezed wholesale electricity price spreads between the Northwest and Southwest through congestion charges at the ISO’s border with Oregon, benefiting California parties at the expense of those in the Northwest. (See Powerex Report Expands NW Cold Snap Debate.)
Reiterating the points in the issue alert, Spires added that Markets+ “creates the opportunity for more equitable outcomes by leveraging its independent governance, its impartial operator and SPP’s demonstrated ability to negotiate seams agreements on a peer-to-peer basis with neighboring markets.”
The alert is the fourth published in a series of seven notices intended to highlight Markets+’s purported advantages over CAISO’s Extended Day-Ahead Market (EDAM) and WEIM. The first covered differences between how the two markets would be governed, the second focused on reliability, and the third compared pricing practices.
The contributing parties include Arizona Public Service, Chelan County Public Utility District (PUD), Grant County PUD, Powerex, Public Service Co. of Colorado, Salt River Project, Snohomish PUD, Tacoma Power, Tri-State Generation and Transmission Association, and Tucson Electric Power.
In the recent alert, the backers argue that Markets+ is a neutral market operator and can, therefore, resolve seams issues between adjacent balancing authority areas and adjacent transmission service providers (TSPs) more equitably than CAISO’s EDAM.
“For entities outside California, joining EDAM would mean accepting that their BA-to-BA and TSP-to-TSP seams will be resolved by market rules developed by the CAISO under its governance framework, and implemented by a market operator that is also one of the participating BAs and one of the participating TSPs,” the alert said.
Additionally, allowing CAISO to set the rules could lead to the California load receiving priority over other regions during heat waves, according to the alert. The parties also argued that CAISO’s market rules have led to concerns over inequitable distribution of congestion value, a point emphasized in Powerex’s March report.
Instead of relying exclusively on CAISO to resolve seams issues, the entrance of Markets+ will lead to each market operator attempting to ensure “that its participants receive the fair value of trade at each applicable seam, including through seams agreements negotiated between these peer market operators, as is the practice today between adjacent organized markets in the Eastern Interconnection,” according to the alert.
Trade across seams also is enhanced under Markets+ because it removes trade barriers and uses a flow-based dispatch, which will “facilitate greater reliability and economic benefits relative to today by enabling more transfers across the same transmission infrastructure, including across BA-to-BA and TSP-to-TSP seams,” according to the alert.
‘Equitable and Efficient’
In response to the issue alert, CAISO spokesperson Anne Gonzales told RTO Insider the ISO remains focused on “implementing EDAM in a manner that best meets the needs of the region’s diverse interests.”
“We continue to work with our partners to advance the Western energy markets, including the equitable and efficient management of seams with neighboring areas — whether in organized markets or not — and to grow its footprint to deliver maximum reliability, economic and environmental benefits to customers West-wide,” Gonzales said.
In its own March report on the January cold snap, CAISO contested the negative characterization of how it managed flows across its seam with the Northwest during the deep freeze, contending that the event mostly demonstrated the value of the WEIM under stressed grid conditions, while the associated congestion charges reflected the functioning of mechanisms seen in any organized electricity market. (See NW Freeze Response Shows WEIM Value, CAISO Report Says.)
The prospect of seams has been an especially fraught issue in the competition between Markets+ and EDAM.
EDAM’s key supporters, who champion the cause of a single electricity market in the West that pointedly includes California, have warned that a divided West will prevent the region from realizing the full “diversity benefit” of resources across its broad footprint and could increase future reliability risks.
On the other hand, Markets+ backers have played down any risks associated with seams. During a May workshop, Bonneville Power Administration officials noted the agency has deep experience dealing with market seams and made clear that seams concerns would not dictate its choice. (See Seams Concerns Won’t Drive Day-ahead Market Decision, BPA Says.)
For its part, SPP has said it is prepared to take a leadership role in managing Western seams based on its own experience developing seams policies with markets neighboring its RTO in the Eastern Interconnection — a point reprised in the Sept. 18 alert. (See SPP’s Experience with Seams Could Help Markets+.)
The 8th U.S. Circuit Court of Appeals on Sept. 16 denied review petitions by several SPP members over FERC’s rejection of generators’ rehearing requests seeking compensation under tariff Attachment Z2.
The court said it found “no error” in FERC’s 2022 decisions and rejected the petitions filed by EDF Renewables, Enel Green Power, NextEra Energy Resources and Southern Power (23-1520, et al.).
At issue is Attachment Z2 of the SPP tariff, under which transmission upgrade sponsors receive credits from any upgrade users whose service could not be provided “but for” the upgrade. The attachment also requires the RTO to invoice the charges monthly and to make any adjustments within one year. Because of software problems, it took SPP eight years to implement the attachment before 2016, during which the RTO did not invoice for the upgrade charges.
FERC found in four separate orders that SPP had violated the filed-rate doctrine, its tariff and its contracts with three of the four generators. However, the commission declined to grant a remedy, citing the one-year limitation on adjusting bills for customers. It also noted that SPP is a nonprofit entity with no independent funds to cover requested remedies.
The 8th Circuit concluded that although Attachment Z2 — and its requirement for upgrade credits — is part of the filed rate, FERC did not violate the filed-rate doctrine by not granting credits to the generators. The court said Attachment Z2 does not conflict with the billing requirements of the tariff and found that it “sets out the arrangement for sharing upgrade costs” but is silent on the timing of billing for upgrade charges.
“The commission thus had only one choice regarding [SPP’s] customers: adhere to [the tariff] and the filed-rate doctrine,” the court wrote.
The generators also contended that FERC failed to adequately explain whether its decision was based on a lack of authority or an exercise of equitable discretion, but the 8th Circuit disagreed, saying the commission “articulated a satisfactory explanation for its orders.”
And “in any event, any error in failing to explain would be harmless here, because the agency was required by law to decline the requested remedies, and a remand would be unnecessary,” it concluded.
A similar request by other SPP members was denied in 2023 by the D.C. Circuit Court of Appeals, which said it lacked jurisdiction to consider the utilities’ filed-rate doctrine argument because they failed to exhaust it at the rehearing stage. (See Appeals Court Denies Review of SPP Z2 Charges.)
