FERC said last week it remains dissatisfied with PJM’s and SPP’s financial transmission rights (FTR) credit policies, while ending inquiries into those of CAISO, ISO-NE and NYISO.

The commission ordered PJM to institute a 99% confidence interval in its policy and said SPP’s tariff “appears” to be unjust and unreasonable in the absence of a mark-to-auction collateral requirement or comparable alternative.

Following a 2021 technical conference on RTO/ISO credit practices, FERC in July 2022 opened investigations under Section 206 of the Federal Power Act into SPP, CAISO, ISO-NE and NYISO. (See “Collateral Requirements” in FERC Proposes Allowing RTOs to Share Credit-related Info.)

The commission said it was concerned the grid operators’ tariffs did not ensure that FTR traders maintain sufficient collateral to reduce mutualized default risk, where a default by a market participant unsupported by collateral must be socialized among all participants.

The commission’s concerns were sparked by the 2018 bankruptcy of GreenHat, which cost the PJM membership nearly $180 million — only $1.4 million of which could be recovered from the company’s principals once GreenHat was insolvent. (See FERC OKs GreenHat Settlements.)

Excluding PJM and SPP, the commission last week found the other grid operators’ tariffs remain just and reasonable and terminated their proceedings. (See below.)

PJM Ordered to Institute 99% Confidence Interval

In its Sept. 21 order on PJM, FERC accepted all aspects of the RTO’s June 2022 filing revising its FTR rules, except for the RTO’s proposal to use a 97% confidence level in its historical simulation (HSIM) model. It ordered use of a 99% level instead (EL22-32).

The commission said a 97% confidence interval would capture only events occurring more than once every 2.75 years, failing to account for rare, but high-risk events such as large, unexpected transmission outages or the February 2021 winter storm that caused generation outages across Texas.

“The record before us fails to show that considering such a short period of time will produce adequate collateral requirements, as it would exclude major, albeit potentially infrequent, events that cause significant price moves affecting the value of FTRs. For example, such a short period of time could exclude extreme but foreseeable events like Winter Storm Uri or the 2014 Polar Vortex, which occurred more than three years apart,” the order states.

The commission said the 99% value would include events that occur at least once every 8.25 years. It directed PJM to submit a compliance filing within 30 days reflecting the change.

“As a general matter, FTR market participants should be, and are, in the best position to bear the principal cost of insuring against their risk of defaulting on the FTR portfolio positions that they acquire voluntarily. An HSIM model with a 99% confidence interval puts that principle into practice by striking an appropriate balance in requiring adequate collateral to protect market participants against the consequences of default without begetting the adverse impacts, e.g., reduced market liquidity, of over-collateralization. And contrary to PJM’s earlier claims, there appears to be little danger of significant ‘collateral shock’ or ‘market disruption’” by requiring FTR market participants to cover more of their own risk instead of transferring a portion of it to other PJM members,” the order states.

FERC agreed with the Independent Market Monitor’s contention that PJM’s cost-benefit analysis was flawed and did not capture the full benefits of a 99% vs. 97% confidence interval. PJM held throughout the proceeding that the costs of a 99% interval would exceed the benefits; several load serving entities, including Duke Energy and Old Dominion Electric Cooperative filed comments agreeing with PJM’s stance.

The commission accepted the remainder of PJM’s filing as is, including replacing the long-term FTR credit recalculation with real-time price updates, revising the $0.10/MWh volumetric minimum charge to apply after adjusting for auction revenue rights credits or mark-to-auction value and revising its tariff to explicitly state that a decline in FTR portfolio value leads to an increase in the FTR credit requirement, as well as the inverse. The order also removes the undiversified adder, which applies to market participants deemed to present heightened risk from being undiversified. Following the GreenHat default, PJM said, the adder was determined to not correlate with fluctuating market risk.

SPP Ordered to Show Cause on Lack of Mark-to-auction Mechanism

In a separate order, the commission expanded the scope of its show cause proceeding for SPP and directed further briefing (EL22-65).

The commission gave SPP 60 days to show cause as to why its tariff remains just and reasonable and to respond to eight questions. It directed the RTO to explain the tariff changes it believes would remedy FERC’s concerns.

The commission faulted SPP’s transmission-congestion rights (TCR) market for lacking a mark-to-auction collateral requirement or a comparable alternative. The mechanism can mitigate excessive risk-taking by allowing the grid operator to make a collateral call if auction prices reveal that FTRs acquired in a prior auction are declining in value.

The commission said SPP’s credit policy failed to “address the credit default risk the commission identified in the show cause order.”

The commissioners said the RTO’s existing reference price methodology relies solely on historical congestion patterns and does not incorporate updated TCR portfolio valuations. FERC also said SPP’s improved credit requirements for TCR market participants did not directly address the increased default risk.

The commission said it remained “concerned” that a mark-to-auction mechanism or comparable alternative was not included in SPP’s tariff and noted the grid operator said its TCR auction process is not within the show cause order’s scope. FERC said SPP’s response raised issues that “require augmentation of the existing record” and it included a list of questions.

SPP staff said they are reviewing the order and plan to respond by Nov. 20.

CAISO

In terminating the proceeding regarding CAISO, the commission found that the ISO’s mark-to-auction valuation addresses the risk that an FTR portfolio — congestion revenue rights (CRR) in CAISO’s nomenclature — may decline in value over time (EL22-62). “We also find that CAISO’s existing volumetric alternative minimum collateral approach ensures that market participants maintain some minimal level of collateral that scales with the size of their CRR portfolio and cannot minimize their required collateral without correspondingly reducing their risk,” the commission said.

“The risk of a CRR portfolio changing over time is captured by incorporating the most recent CRR auction results as part of the financial security requirement calculation,” the order continued. “As noted in CAISO’s response, this approach incorporates a mark-to-auction mechanism and captures risks that emerge when auction results diverge materially from historical outcomes.”

The commission said several other factors reduce overall risk in the CAISO CRR market: CRRs are offered with a maximum open position of only three months and may be purchased only for paths associated with physical supply delivery.

The commission noted that CAISO uses a different approach from PJM, MISO or SPP, all of which require a flat $/MWh amount on FTR portfolios. “CAISO nonetheless requires a volumetric value to be posted as collateral that is weighted to produce a $/MWh amount, which imposes a higher requirement on negative or low positively valued CRR portfolios,” it said.

ISO-NE

FERC said ISO-NE’s collateral requirements are just and reasonable, agreeing with the grid operator that the tariff’s existing provisions require market participants to maintain collateral scaled to the size and risk of their FTR portfolio (EL22-63).

It agreed with the RTO that “the lack of a volumetric minimum collateral requirement does not render ISO-NE’s existing collateral requirements unjust and unreasonable.”

The commission took issue in the show cause order with ISO-NE’s lack of a volumetric minimum collateral requirement. The RTO responded that it is already well protected from risk due to its FTR financial assurance requirements and the fact that it doesn’t offer long-term FTRs.

NYISO

The commission said NYISO convinced it that it has adequate protections against defaults in its FTR market — called transmission congestion contracts (TCC) — despite the absence of a volumetric alternative minimum collateral requirement (EL22-64).

The commission cited the ISO’s alternative approach to ensure market participants “maintain some minimal level of collateral that scales with the size of their FTR portfolio and cannot minimize their required collateral without correspondingly reducing their risk.”

Unlike PJM and MISO, NYISO requires full payment for TCCs purchased in auctions upon completion of the auction, except for the second year of a two-year TCC. “We find that this key difference in settlement design ensures that market participants at a minimum must post the full auction price of an awarded TCC and, thus, prevents a market participant from minimizing its collateral without reducing its risk,” the commission said.

The commission cited a NYISO analysis that found the grid operator’s existing collateral requirements — $0.15/MWh for balance-of-period TCCs, $0.40/MWh for future six-month TCC, and $0.053/MWh the second year of a two-year TCC — were always greater than the minimum requirements in other markets ($0.10/MWh for PJM and SPP, and $0.05/MWh for MISO).