In the race between system operators to capture power providers in the rich Mountain West energy market from New Mexico to Idaho, the California Independent System Operator (CAISO) took the lead in 2020, but two competitors are at its heels.
CAISO pulled ahead of the Southwest Power Pool (SPP) by adding Xcel Energy's Colorado subsidiary to its Western real-time balancing market and filing its initial proposal for expanding to day-ahead trading during the summer. But SPP recently won approval from federal regulators for a Western real-time market to expand its regional system. And some Colorado power providers want their own market.
A January Brattle Group study showing "greater potential to lower production costs" for Xcel in CAISO's energy imbalance market (EIM) than in SPP's proposed energy imbalance service (EIS) was decisive in its choice of CAISO, Xcel Energy - Colorado President Alice Jackson said. But CAISO's day-ahead market is undefined, SPP's WEIS is not yet fully defined, and "a single market solution for Colorado would be preferable," she acknowledged.
Economic pressures and policy initiatives driving traditional generation closures and variable renewables growth make an imbalance market for the West's 39 balancing areas necessary, power providers and stakeholders said. But SPP and CAISO offerings are just emerging, and some in Colorado say a single state marketplace for Colorado power providers would be wiser until other options are defined with more certainty.
President-elect Biden is committed to meeting climate challenges and national policy is building from the states toward clean energy and zero emissions targets, Western Grid Group Managing Director Amanda Ormond said. "To meet those goals, utilities need to be part of a larger marketplace. The only bad option is not choosing one."
With major utilities in the Southeast and the Mountain West now moving to seize the economic and reliability opportunities that power markets offer, the decision by Mountain West policymakers, power providers and stakeholders on which path to take could be instructive about what market structures most effectively offer those opportunities.
Why Xcel picked CAISO
CAISO's voluntary EIM was launched by the PacifiCorp subsidiary of Warren Buffett's Berkshire Hathaway Energy and CAISO in November 2014 to optimize real-time dispatch. With Xcel Colorado, the 11 participants of California's EIM now have 11 applicants and all 22 power providers are expected to be participating by the end of 2022, doubling the market's potential to improve reliability and reduce customer costs. At the end of Q3 2020, it had generated $1.1 billion in cumulative benefits since 2014.
Estimated production cost benefits, largely from reduced fuel expenditures, for Xcel and three small utilities — Black Hills Energy, Platte River Power Authority and Colorado Springs Utilities — in a joint dispatch agreement from the EIM are about $1.98 million per year total, Brattle found. With SPP's proposed EIS they would be about $1.62 million per year, even if other Mountain West utilities also join the joint dispatch agreement.
One difference is the CAISO EIM's resource diversity — its solar resources in the Southwest and hydropower in the Northwest allow "more opportunity to economically trade power across the footprint," Brattle said. The report also found CAISO offers lower administrative costs and better "transfer capability" between the Colorado utilities and California.
Another feature of the CAISO EIM that impacted Xcel's decision was the plan to expand to day-ahead market services, Jackson said. Day-ahead services would allow participants to obtain savings in most of Western energy trading instead of in the 5% of trading that takes place in the imbalance market.
The EIM has helped absorb California's solar oversupply and meet its morning and evening peaks, Berkshire Hathaway Energy Vice President for Government Relations Jonathan Weisgall added. "A voluntary day ahead market will allow optimal dispatch flexibility to meet increased variability from the West's growing renewables and zero emissions mandates while securing cost savings for customers."
CAISO's work on a voluntary Extended Day-Ahead Market (EDAM) began after the 2018 California legislature's rejection of proposed CAISO governance changes needed to form a full regional energy market. EDAM would expand regional dispatch from the EIM's 5% of Western power flows to almost 100% of its electricity market trading.
EDAM benefits would likely not equal the $1.5 billion a 2016 Brattle study estimated would come from a full Western region energy market, said Brattle Group Principal Hannes Pfeifenberger, who led the study. But they would be greater than the $296.9 million optimized dispatch provided in 2019, he said.
Solutions to the challenges of transmission planning, charging across jurisdictions, and guaranteeing participants they will meet their own reliability obligations were proposed by CAISO Staff in July. And other details of an organized electricity market, like price bidding and clean energy credits, can be settled later, they said.
But EDAM will only be possible if participants in and outside California resolve differences on governance in a way that allows both a satisfactory role in decision-making. California leaders want to protect the state from federal regulation and interference by other states while other Western state leaders require a CAISO governance structure that allows them to protect their state's interests from California, which California's legislature rejected.
Reconciling this contradiction will require new market rules agreed to by the EIM Governing Body and the CAISO Board, an October 2019 CAISO paper reported. Now in the second phase of the process, there is still no final consensus for a "joint authority" structure and potential participants, including utilities from New Mexico to Idaho, are already looking at the SPP and Colorado alternatives.
Being a part of CAISO's EIM "allows us to exchange energy with an even larger group of neighboring utilities and integrate more clean energy into the system," Jackson said. But a regional market is "needed to achieve our carbon goals."
While California works on the next step toward a full regional market, many Mountain West power providers are already working with SPP.
The SPP offer
Production cost benefits "are only one element of evaluating participation," according to Brattle. Congestion, load uncertainty, implementation, administrative and transaction costs, and governance flexibility related to market participation are also important, the group added.
SPP manages electricity across 17 states in the Eastern and Western Interconnections, from the Mississippi River to the Rockies and from North Dakota to Texas.
Over decades of expansion, it has developed a governance framework that gives all its member states a voice in decision-making, said former SPP Chief Operating Officer Carl Monroe, now an independent power system consultant. "It has been called a federalism model that allows shared jurisdiction."
This reduces the risk associated with an entity's participation, like being obligated to incur expenses for transmission that the entity does not want to make, he added. Joining SPP "was the lowest and, therefore, the most favorable option from a qualitative risk standpoint," reported a 2014 assessment by the Western Area Power Administration (WAPA) ahead of joining SPP's full regional market.
Current regional market members Tri-State Generation & Transmission, Basin Electric, and WAPA were named expected participants in SPP's recent proposal to federal regulators for a Western EIM.
"Choosing an imbalance market is not just based on what can be quantified," Brattle Senior Associate John Tsoukalis said. "The familiarity those utilities have with SPP is a key part of their decision to join its EIS. They know its stakeholder process works well for them."
In its decision to join the EIS, Basin Electric found that SPP's "proven track record and collaborative stakeholder process," made it "the obvious choice," said Senior Vice President of Transmission, Engineering, and Construction Tom Christensen.
But there will also be $49 million in annual savings from optimized dispatch and reduced fuel costs for current and new members of SPP's WEIS, a recent SPP-Brattle Group study found. Of that, $25 million in annual production cost savings and revenue would go to the new Mountain West utilities that join the WEIS, and there would likely be additional value from real-time dispatch, achieving policy goals, reduced reserve requirements, and consolidated planning.
WAPA's 15-state footprint has 10,570 MW installed capacity, 17,325.5 line-miles of transmission, and members in both SPP and CAISO, WAPA Administrator and CEO Mark Gabriel said.
WAPA will continue to work with SPP and CAISO because "one size does not fit all and there are opportunities and challenges in both," he said.
Resource diversity is important, but SPP's collaborative market governance was crucial when WAPA's Upper Great Plains members joined in 2015, and members interested in joining CAISO's EDAM "would need the same consideration," Gabriel said. "We are studying next moves, but the analysis is complex."
That complex analysis may also be too preliminary while SPP's Western EIS and CAISO's EDAM expansion are not finalized. A joint dispatch agreement unifying Colorado utilities could provide benefits almost as good while the system operators advance their plans, according to an October Vibrant Clean Energy study.
Colorado now, the West later?
A newly proposed Colorado-centric market could meet the specific preference for a single state market identified by Xcel's Jackson. The potential benefits to Colorado if its power providers stick together were clear in the Brattle study.
If only Xcel and the three small utilities in the joint dispatch agreement join the EIM, their total production costs would improve by 0.44%, Brattle found. But if Xcel, its three joint dispatch agreement entities, and other major Mountain West power providers join CAISO's EIM, their estimated production cost benefit is "about 3.86%," primarily because lower cost resources, largely wind, solar, and natural gas, are more available.
A preliminary and likely conservative estimate of the proposed production cost benefit for the Xcel utilities and the Mountain West utilities moving to SPP's WEIS was 0.36% of their total production costs, Brattle added. That improvement could be bigger as participation expands and more lower cost resources become available for reliability balancing, Brattle's Tsoukalis acknowledged.
These findings were largely confirmed by other data in the Vibrant Clean Energy study commissioned by Holy Cross Energy and the Intermountain Rural Electric Association.
Colorado's 2018 retail rates are expected to drop by $0.027/kWh by 2040 with its power providers divided between systems, according to Vibrant. Its assumption is that the four Xcel entities, Intermountain Rural Electric Association, and Holy Cross Energy would join the CAISO EIM while Tri-State and its members, Basin Electric, and WAPA would join the SPP WEIS.
If all those providers join the EIM, rates would fall an additional $0.0084/kWh, while joining the WEIS together would reduce their rates only an additional $0.0069/kWh because of the reduced lower cost resources currently available for balancing.
Colorado-centric joint dispatch involving as many as 33 of the state's individual power providers would only reduce rates by an additional $0.0035/kWh, but it would be a very easy first step, said Vibrant Clean Energy CEO and report co-author Christopher Clack, a former National Academies of Science researcher.
These benefits can be significant to a utility's customers and to its bottom line, Clack said.
"Splitting the utilities among different EIMs exposes Colorado to competition from the East and West," Clack said. "Colorado wind is more valuable in California than in the Midwest and by joining SPP it misses out on access to very low cost Southwest solar, which means the state loses twice."
Colorado's zero emissions mandate "is not for the mid-2020s, it is for 2050," he said. "Colorado ratepayers can derive important benefits from a state-wide joint dispatch agreement now, wait until the system operators' uncertainties are resolved, and see what the best option is then."
The Colorado-wide joint dispatch agreement is also the only option achievable by Colorado alone, agreed Holy Cross President and CEO Bryan Hannegan. It offers "lower cost electricity, cleaner electricity and more jobs in the near term," and enables greater future leverage for "integrating into a larger regional market."
These concerns are now being studied by regulators and power providers throughout the Mountain West, Western Grid Group's Ormond added. And they could be similar to concerns that power providers in the Southeast and elsewhere will have to consider regarding their need for a market system that improves customer economics and protects reliability.
The resources on the system will change, Ormond added. "Familiarity with a system operator may feel more comfortable, but the more important question may be whether the system operator's vision matches the utility's vision of where it needs to go."
There may not be one right pathway for all states or power providers, and the multiple pathways in the West "show how competition illuminates the best ways forward for the different stakeholders," Ormond said. "Just because we don't know what the ultimate future is does not mean we should stop building larger and stronger markets."
