CAISO's EDAM and DAME have now been live for just over two months, giving market participants an opportunity to assess how the new markets are affecting operations, pricing, and trading strategies. During the recent EDAM and DAME retrospective webinar, we explored early observations on price formation, Congestion Revenue Right (CRR) impacts, and the data now available in Yes Energy. This blog answers the most common questions received during that discussion and highlights what market participants should be watching as these markets continue to evolve.
You can access the greenhouse gas (GHG) prices and the other components of the locational marginal pricing (LMP) in any of the time series views, such as Time Series Analysis and Nodal Profile in PowerSignals, as well as in DataSignals API and Cloud. Yes Energy is also working on integrating the GHG prices into the map and in our Price Table module in PowerSignals.
With EDAM's launch, the internal interties between participating EDAM Balancing Authority Areas (BAA) have become transfer locations, which support the optimized transfer of energy and capacity (IR and RC) across the EDAM footprint. EDAM internal transfer locations are no longer biddable locations for imports or exports, with an exception at the Mona and Crag View interties during an initial transitional period. Bids associated with internal EDAM resources are now submitted at the physical generator's location in the EDAM footprint.
During the initial transitional period, if the source of the generation is not known, intertie bids are allowed for resource adequacy (RA) imports into the CAISO BAA and imports supporting renewable portfolio standard (RPS) contracts. Also, during this transitional period, intertie schedules on the CAISO interties will continue being modeled under the SP-Tie model.
Intertie bids will continue to be supported at EDAM external interties and are modeled under the GAP-Tie model.
Carbon-emitting resources can submit a GHG bid adder to serve load in a GHG regulation area that they are not physically located within. If awarded, the emitting resource would be paid its LMP, which would include the Marginal GHG Cost (MGC) component. While this may increase the resource's revenues, the MGC is designed to recover the carbon compliance costs that those emitting resources incur under a state carbon pricing program, rather than serving additional profit.
Emitting resources outside the GHG area can optionally include the GHG adder, but emitting resources inside the GHG area serving internal load have GHG compliance costs baked into their offers.
Load inside the GHG area will pay more, but the MGC is meant to shield external load, as they don’t have to pay for the incremental costs of resources serving load in the carbon-regulated states.
Yes, the MGC can and will differ between states with distinct GHG regulation standards. Currently, the California cap-and-trade program and the Washington cap-and-invest program do not recognize each other's compliance instruments, so the different GHG regulation areas have separate daily GHG allowance index prices (this could change as soon as 2027, however, as officials are working towards linking the California, Washington, and Québec carbon markets). Subsequently, the market allows emitting resources to submit distinct GHG bid adders and bid capacities to serve load in the different GHG regulation areas. Because the MGC is defined as the shadow price of the GHG Transfer allocation constraint for a specific GHG Regulation Area, the MGC is calculated independently by the GHG area.
If the Marginal GHG Cost (MGC) is positive, an emitting resource from outside of the GHG regulation area is the marginal unit setting the price. Only resources with a non-zero GHG emissions rate can submit GHG bid adders greater than $0, and resources inside a GHG regulation area can’t submit a GHG bid adder to serve load within their own GHG area.
If the MGC is $0, it usually means the marginal unit is zero-carbon, but not necessarily. Submitting a GHG adder is voluntary, so a gas resource could choose to submit a $0 GHG bid adder to improve the odds of being dispatched. The MGC will also be $0 if the GHG Regulation Area is a net exporter, or if the GHG area is net importing but the shadow price of the allocation constraint is zero (meaning there is no difference in the marginal cost of energy inside and outside the GHG area).
The procurement of the new Imbalance Reserve Up (IRU) and Imbalance Reserve Down (IRD) products in the Integrated Forward Market (IFM) reserve transmission capacity and displace energy congestion revenue. As a result, the CRR notional value formula expands from energy-only congestion to also include IRU and IRD congestion components.
IRU and IRD capacity awards are modeled as actual physical energy flows in the IFM's deployment scenarios, and so the IRU and IRD flows can provide counter-flow on congested transmission paths, which effectively displaces the standard energy schedules that would have otherwise generated congestion revenue in the base case.
CAISO now calculates this "displaced congestion revenue" and collects it through the imbalance reserve cost allocation to avoid a shortfall in the collected congestion rent that is paid out to CRR holders. Displaced congestion revenue is calculated as the product of the Imbalance Reserve Flow, the Shift Factor, and the Shadow Price of the transmission constraint, summed across all binding constraints in the upward and downward deployment scenarios.
The RUC MPM pass should have a minimal impact on market performance and solve time because RUC is much less computationally complex than the IFM. The MPM pass was a necessary addition to the RUC process due to the introduction of the biddable, locationally priced Reliability Capacity Up (RCU) and Reliability Capacity Down (RCD) products.
Historically, Resource Adequacy (RA) resources were required to participate in RUC at a $0/MW price, so there was no ability or incentive to economically withhold capacity to manipulate prices. Now, all resources, including RA resources, can submit non-zero price bids for RCU and RCD up to $250/MWh, and these locationally priced RCU and RCD awards include marginal congestion contributions from binding transmission constraints.
All these factors mean that a supplier in a transmission-constrained area could potentially exercise local market power by economically withholding supply to artificially inflate the RCU price. Since these Reliability Capacity bids are evaluated in the RUC optimization after the IFM clears (and the IFM MPM process runs), a dedicated RUC MPM pass is needed to prevent uncompetitive pricing.
The EDAM Wind and Solar Forecast aggregates forecast data by BAA and only posts forecasts for the Day-Ahead Market.
The traditional Wind and Solar Forecast aggregates by trading hub (NP15, ZP26, SP15, PACE, and PACW), and posts forecasts for the Day-Ahead Market, Hour-Ahead Scheduling Process (HASP), the 15-minute market (RTPD), and the 5-minute market (RTD), as well as posting actual wind and solar production data.
Yes, the RUC constraints are now flowing into DataSignals API and Cloud, which is Yes Energy's Snowflake product.
Want to dive deeper into CAISO's EDAM and DAME? Check out our previous blog, CAISO EDAM and DAME FAQ: Virtuals, Physical Trading, and CRR Changes Explained.
Have additional questions about EDAM and DAME or how to analyze the evolving markets? Talk to a Yes Energy expert.