For the past few years, we’ve been tracking the so-far unsuccessful efforts by clean energy proponents and leading California politicians to expand the footprint of California grid operator CAISO to incorporate the rest of the Western U.S.
Proponents of the move say it would save hundreds of millions of dollars with increased efficiencies and expand the market for geographically diverse renewable energy. But they haven’t been able to overcome the political challenges of merging disparate state energy policies into an interstate compact — or California’s fears that the Trump administration may use a newly created market that stretches beyond state borders as an opening to disrupt its clean energy policies.
Even before the most recent legislative failure last year, utilities and regulators eager for the benefits of a pan-Western grid market were exploring alternatives. We’ve discussed some of the concepts at play, such as expanding the already existing real-time Energy Imbalance Market, or EIM.
This real-time market has delivered a collective $736 million in reduced costs since its launch in 2014, with big beneficiaries including CAISO, PacifiCorp, NV Energy, Arizona Public Service, Portland General Electric, Idaho Power, Powerex and Puget Sound Energy.
EIM recently expanded to public entities such as Los Angeles Department of Water & Power, Seattle City Light, Salt River Project, and the Balancing Authority of Northern California. Massive federal hydropower and transmission operator Bonneville Power Administration is in the early stages of joining the market.
In mid-September, 14 of these EIM entities submitted a letter to CAISO and the EIM Governing Body, outlining the most comprehensive plan yet for expanding beyond its real-time boundaries. It’s called the Enhanced Day-Ahead Energy Market, or EDAM, and according to its proponents, it could offer aggregate benefits of up to $227 million per year, as long as it attracts broad participation across the West.
That's a conservative estimate of the savings that could come from opening up the West's transmission system to day-ahead trading, Carl Zichella (Western transmission director for the Natural Resources Defense Council, an organization that's a big backer of regional grid expansion) said in an interview this week. Still, it’s “enough for the utilities involved to want to move forward with this,” he said.
Compared to the political strife that doomed California's legislative efforts at grid expansion, a commitment to "exploring" a day-ahead market from a variety of investor-owned and public utilities is "a sign that they’re ready to take the next step," Zichella said.
That's an important stake in the ground in what's sure to be a years-long effort, but one that Zichella believes is inevitable, given its benefits.
EIM’s real-time trading has had clear benefits. But it relies primarily on “residual capabilities of resources that are largely committed further in advance,” the letter states. In other words, it’s only tapping the limited flexibility of power plants and other grid resources that have already had their operating scheduled determined by commitments made in advance.
Among the 38 balancing authorities that constitute the Western U.S. transmission network, these commitments make up the vast majority of transactions. And that’s bound to be less efficient than a system that can expose and make markets for differences in cost and price across entire regions, as proponents of Western grid regionalization have noted in multiple studies.
The benefits could be huge, given the scale of the energy markets involved. A 2018 analysis from the nonpartisan Next 10 Foundation projected up to $1.5 billion per year by 2030 in reduced energy costs in California, due to more competition, economies of scale, and cheap regional wind and solar power.
Just how these benefits will stack up depends on how the market is constructed, however — an important consideration, given that the envisioned market would be large enough to potentially reduce “existing bilateral market activity and opportunities" in the region, the letter said.
But EDAM isn't meant to have the authority to dispatch generation directly or assess transmission costs across its network. That’s a key difference that separates it from a full-fledged grid operator like CAISO and the independent system operators and regional transmission organizations that manage transmission for two-thirds of the country.
There are political considerations behind this. As Zichella noted, “Nothing’s going to happen before the 2020 election,” given the lack of trust California lawmakers and regulators have in the Trump administration not to interfere in any climate change-related efforts that involve federal oversight. And because it's expected that creating an EDAM will take several years at least, “one of the things that could happen between then and now is the politics could change at the national level, and there could be more impetus to move to a [regional transmission organization]."
But as the utilities made clear in their letter last month, even expanding the EIM to a day-ahead construct involves a host of complex issues. Until these issues are resolved, there’s no way to tell if the market will work for individual participants, or how many will need to join to make it worthwhile.
That’s why the letter makes clear that participating utilities haven't yet made a commitment to EDAM, instead pledging only to "develop a comprehensive market design proposal." In other words, whether or not EDAM will become something more than a plan to make a plan will depend on what happens next.
Thorny issues ahead
EDAM’s first challenge is likely its most easily solved: creating a governance structure that represents the interests of its members.
The existing EIM Governing Body does provide a “logical framework" for that task, the letter states. As Zichella noted, the board has earned participants’ confidence and is already working with CAISO.
EDAM’s second challenge is a bit more daunting: to assure that all participants “have each secured sufficient energy, capacity, flexibility, and supporting transmission,” a combination of needs it groups together under the category "resource sufficiency." EDAM won’t be able to modify state or local control over long-term resource adequacy planning and integrated resource planning. That means it needs assurance that EDAM transactions from one region won't lead to reliability shortfalls in other regions, or allow unscrupulous participants from “leaning” on the capacity and flexibility investments of other regions.
EDAM’s third challenge lies in adapting the existing open access transmission tariffs in use across most of the West to support its day-ahead trading. This is a much more significant challenge, Zichella noted, with a more diverse set of potential solutions.
Transmission capacity must be made available for electricity to flow from region to region on the pathways determined to be most cost-effective by EDAM’s day-ahead market software. That capacity will come either from new transmission lines, like those being built from wind-rich Intermountain states to West Coast markets, or from existing transmission lines, with their existing bilateral agreements and open access transmission tariffs.
EDAM will have to create market constructs that give transmission operators enough revenues to make it worth participating, without setting excessively high transmission “hurdle” rates that prevent the market-clearing transactions identified by market software from being executed in the real world.
The letter suggests two potential solutions to make transmission capacity available in exchange for incremental rates, or the rights to earn “congestion rents” on the transmission paths chosen by the market software.
Pleasing California and Wyoming
“Price formation” is the fourth key issue raised by the EDAM proposal — an important factor for a market that could eventually replace much of the West's existing day-ahead bilateral transactions. Beyond creating a new value for this massive day-to-day trade in electrons, these new prices become references for valuing and settling forward contracts, pushing their effects into the future as well, the letter noted.
But creating an effective price formation regime for EDAM will be complicated by the differences between CAISO’s method of dispatching bids and calculating energy prices in its day-ahead market, and the firm, capacity-backed energy products traded in most Western bilateral day-ahead transactions.
EDAM’s fifth and final challenge pertains to greenhouse gas emissions.
Many of the states and utilities involved in EIM have or are working on greenhouse gas (GHG) emissions reduction targets and zero-carbon energy mandates, among them California and Washington. But others such as Arizona have voted down clean energy mandates, or have taken steps to force utilities to keep coal-fired power plants open, as with Wyoming.
These mandates will have profound effects on the electricity market that EDAM is meant to coordinate. And last month's letter makes clear that the parties involved haven’t come up with the solution, beyond saying that it should be approached “from a fresh perspective.”
On the side of states seeking to limit carbon emissions, failure to value those efforts could lead to "inappropriate shifts in GHG-related compensation from clean suppliers to emitting resources and energy marketers," it wrote — a point underscoring the concerns of opponents to previous Western grid expansion proposals, who feared it could lead to California and other clean energy states buying power from coal power plants in Wyoming and Utah.
On the other hand, jurisdictions without greenhouse-gas pricing policies are seeking assurances that they won't be "improperly" charged for those costs in other states, and that their own renewables fleets won't be "unfairly disadvantaged" in those clean energy states.
Any EDAM will also need to incorporate changes to state policies in the years to come. Given these uncertainties, this could end up being the most challenging issue facing a pan-Western grid market.