CAISO’s Extended Day-Ahead Market clinched a set of wins Aug. 29 when FERC approved the market’s revised congestion revenue allocation model and authorized participation for the EDAM’s first two members — PacifiCorp and Portland General Electric, which will join the market in 2026. 

The three decisions are interlinked in that PacifiCorp’s EDAM membership tariff filing to FERC triggered the events that prompted CAISO to revise the EDAM’s congestion revenue allocation rules. 

Shortly after Portland, Ore.-based PacifiCorp submitted the filing to FERC in January, Powerex, the energy trading arm of Canadian utility BC Hydro, issued a paper contending EDAM contained a “design flaw” in how it treated firm transmission rights and congestion. Powerex argued the design would leave the market’s non-CAISO participants exposed to charges for constraints occurring outside their systems while not providing them the ability to recover or hedge against those costs. (See Powerex Paper Sparks Dispute over EDAM ‘Design Flaw’.) 

Powerex’s argument centered on the possible impact of “parallel” — or loop — flows in EDAM. As an example, the company’s paper cited how an energy delivery scheduled between PacifiCorp’s East and West balancing authority areas could produce a parallel flow that causes congestion in the CAISO BAA. EDAM then would apply the charge for that CAISO congestion to the PacifiCorp transaction but not provide the PacifiCorp transmission customer with an adequate ability to hedge for that charge, including through an allocation of congestion revenues.  

CAISO and PacifiCorp initially defended EDAM’s congestion revenue allocation (CRA) design, noting FERC already implicitly endorsed the model when it approved the day-ahead market’s tariff in December 2023. But after a broader group of stakeholders expressed similar concerns, the ISO in March launched an “expedited” initiative to address the issue. (See Fast-paced Effort will Address EDAM Congestion Revenue Issue.) 

Under the new design coming out of that stakeholder process — and now approved by FERC, certain congestion revenues stemming from parallel flows would be allocated to the BAA where the energy is scheduled rather than where the constraint is located. Those revenues would be allocated based on a transmission customer’s eligible firm Open Access Transmission Tariff transmission rights submitted and cleared as day-ahead balanced self-schedules. (See CAISO Approves New EDAM Congestion Revenue Allocation Design.) 

In its decision (ER25-2637), the commission found the revised rules to be “just and reasonable” because “they will allocate a portion of certain congestion revenues associated with a binding constraint to the EDAM BAA where market participants paid congestion costs associated with the constraint, rather than to the EDAM BAA where the constraint occurs.” That will ensure “eligible” firm transmission customers can hedge against day-ahead congestion charges by submitting their self-schedules, the commission said. 

The commission noted that commenters in the proceeding “largely support” the proposal as an “interim measure” until CAISO comes up with a permanent solution through its stakeholder process. 

“CAISO frames the instant proposal as a ‘transitional measure,’ and, after EDAM goes live, CAISO states that it intends to begin a stakeholder process, informed by operational data, to identify near-term and long-term revisions for congestion revenue allocation under EDAM,” FERC wrote. “We note, however, that the instant proposal does not contain a sunset date. As such, although some commenters are concerned that future tariff revisions might again expose their firm transmission use to congestion charges, such concerns are outside the scope of the instant proceeding.” 

The commission acknowledged the concerns of some commenters that the rule changes could incentivize increased use of self-schedules among EDAM participants as a means to hedge against congestion charges but said that practice is not “inherently undesirable” because it could make supplies available to CAISO’s markets. 

“In any case, even if CAISO’s proposal may further incentivize self-scheduling, we note that, under EDAM’s current market design, the ability to self-schedule helps participating transmission providers respect their transmission customers’ firm transmission service rights, a consideration that must be balanced against any potential market impacts. We find that the likely benefits of EDAM’s market dispatches will still incentivize market participants to economically bid into EDAM,” the commission wrote. 

The commissioners disagreed with commenters — including Powerex — which argued CAISO should allocate congestion revenue directly to transmission customers based on their transmission rights and allow those customers to opt their transmission service rights out of EDAM altogether, as provided for in SPP’s Markets+. 

“The commission has already accepted in the EDAM order CAISO’s allocation of congestion revenue to EDAM entities, who in turn sub-allocate the congestion revenue as provided for in their OATTs. Similarly, with respect to transmission carveouts, the EDAM order approved the CAISO tariff section that provides EDAM entities the discretion to determine the criteria for such carve-outs,” FERC wrote. 

The commission also rejected various requests that CAISO be required to: “immediately begin a stakeholder process to identify near-term solutions to the issues of the asymmetry between EDAM BAAs” and the incentive to self-schedule; delay EDAM’s implementation until a long-term solution for CRAs is identified; or submit CRA rule revisions within two years. 

“We disagree with protesters that a deadline for further deliberation should be mandated as we find that CAISO’s current allocation methodology for congestion revenue is just and reasonable. Moreover, we will not direct CAISO to delay the go-live date of a market expansion that the commission has already found to be just and reasonable,” FERC wrote. 

Orders Pave Way for PacifiCorp, PGE to Join EDAM

The CRA issue appeared prominently in the FERC orders approving the utility tariff revisions required for PacifiCorp (ER25-951) and PGE (ER25-1868) to participate in the EDAM, particularly around the sub-allocation of the congestion revenues back to load-serving entities in the utilities’ BAAs. 

Over the protests of multiple commenters, the commission approved each utilities’ two-step process for sub-allocating those revenues.  For both utilities, Step 1 of the process seeks to use EDAM’s congestion revenue allocation to reverse day-ahead congestion price differentials arising for self-scheduled energy transfers relying on firm monthly and longer-term transmission service rights. Step 2 will distribute the rest of the allocation to BAA load and exports not already included in the step one allocation. 

Using similar language in both rulings, FERC said it found the Step 1 allocation just and reasonable because “it first reverses day-ahead congestion charges on balanced self-schedules associated with long-term transmission service rights to the greatest extent possible, providing long-term firm customers that choose to self-schedule “an opportunity to hedge against day-ahead congestion charges associated with their use of” the transmission system “by submitting balanced self-schedules in the day ahead.” 

In the PacifiCorp decision, the commission noted that “[w]hile protesters argue that firm transmission customers may not be able to reverse their day-ahead congestion charges if PacifiCorp is not allocated sufficient congestion revenue, we agree with CAISO and PacifiCorp that these issues are outside the scope of the instant proceeding because they pertain to tariff provisions that the commission accepted in the EDAM order.” 

Both utilities’ orders point to the concurrent CAISO CRA order, noting the ISO’s tariff revisions “may help to address some of the concerns” raised by protesters in the two proceedings. 

Both orders also reject arguments by future participants of SPP’s Markets+ that the commission reject tariff provisions around transmission scheduling because they don’t accommodate the ability of transmission rights holders to contribute their transmission to Markets+. In both orders, FERC found the revisions do “not bar firm point-to-point transmission customers from contributing their transmission rights to Markets+, insofar as they are able to meet all of the requirements of” the utilities tariff. 

FERC found “there is no obligation under the commission’s regulations, or the pro forma OATT” for either utility “to accommodate transmission contributions to Markets+.”