ISO-NE will not use Sunrun’s DER aggregation until 2022 and now only uses aggregated DERs for demand response, ISO-NE spokesperson Matthew Kakley said in an email.
CAISO also allows DER aggregations to participate in its markets as demand response tools to reduce loads, but not as generation, spokesperson Anne Gonzales said in an email. Utilities in California use DER aggregations through the state-authorized Demand Response Auction Mechanism (DRAM) to meet part of their resource adequacy must-offer obligations.
The grid operator is currently developing another model — the Distributed Energy Resource Provider participation model — that will allow DER aggregations “to offer wholesale market services comparable to other generating resources,” Gonzales said.
“Though it is technically possible, no system operator has implemented a practical participation model that addresses both the load and generation capabilities of DER aggregations,” said Ted Ko, vice president of policy and regulatory affairs for Stem, a smart storage provider, which has aggregated storage participating in the CAISO DRAM.
When FERC develops a final rule for DER aggregations, it should follow a set of “principles” for participation, Ko wrote in his comments following the 2018 technical conference. DER aggregations should be allowed full participation, not be denied participation without proven risk of market distortion or threat to reliability, and rules should enable “multiple uses” of DERs with “multiple market values” as load reduction or generation, he argued.
“Power system operators who become familiar with the new flexible resources’ variability can use them to change the need for capacity markets and big reserve margins.”
Pat Wood III
Former FERC Chair
Perhaps most importantly, aggregations should be “treated as a single resource, with the ISOs designing rules and processes at the pricing node level of granularity, not individual sites,” Ko wrote.
The DER aggregation regulation pursued in FERC’s 2016 rulemaking and 2018 proceeding “is still sitting there,” former FERC Chair Jon Wellinghoff said. But “the recent circuit court decision on Order 841 made clear FERC has jurisdiction to implement market rules that can deliver a flood of consumer-owned flexibility to the system.”
New technologies could “enable consumers to participate in wholesale markets individually and give retail aggregators a new opportunity to supply wholesale markets,” Wellinghoff added.
DER aggregation may be an important factor in moving away from capacity markets, former FERC Chair Pat Wood III agreed. “Power system operators who become familiar with the new flexible resources’ variability can use them to change the need for capacity markets and big reserve margins,” he said.
RA analysis is “the quantitative work to determine the procurement needed to serve load and protect reliability,” Stenclik said. “Historically, serving load meant serving peak load, but with the pandemic and extreme weather events and changes in consumer usage, reliability threats are no longer always at peak load.”
Flexible loads and flexible generation can shave and shift peaks with distributed renewables, storage, demand response or managed electric vehicle charging, Stenclik added. To do that effectively, “the power sector must understand this new flexibility well enough to rethink its approach to RA and metrics like outage rates, and methods of analyzing reliability must evolve.”
Five new principles can “ensure that enough resources are available for modern power systems, regardless of the technologies,” according to Stenclik’s just-published paper. The paper is one of the first efforts to develop such principles — “really important work,” according to Ric O’Connell, executive director of power market and regulatory proceedings consultant GridLab.
The first principle says that DER, the technologies that manage it, and advanced rate design can make demand more responsive to price signals. That “may shift the resource adequacy planning challenge away from reliability needs toward economic considerations, as customers determine and differentiate which loads matter most.”
Second, as NERC foresaw in 2017, DER penetrations on distribution systems are reaching high enough levels that RA analysis must include both near- and long-term planning, the paper said. And analyses and planning approaches that include long-term forecasts of costs, benefits and risks must become “the new gold standard” for RA analysis.
“Many states have very aggressive clean energy goals or mandates, but the markets are not structured to accommodate aggregated DERs and other resources needed to meet them.”
Policy and Storage Market Strategy Director, Sunrun
Third, changing demand makes conventional RA metrics for estimating outages too narrow, the paper said. New metrics should quantify outages’ “frequency, duration, and magnitude in MW and MWh” to “put the emphasis on individual, rather than aggregate, event characteristics.” That will lead to mitigations with “appropriately sized” resources and “avoid over-procurement.”
Perhaps the paper’s most important principle is that “there is no such thing as perfect capacity,” Stenclik said. Different resources address different needs. Batteries can serve short-duration shortages, but demand response or pumped hydro storage may be better for long-duration outages. RA analyses should recognize “there is no perfect resource” and “all resources have limitations.”
Finally, the economic or financial aspects of reliability should be transparently assessed to ensure that “customers are not being asked to pay more for reliability than it is worth,” the paper said.
Because today’s power system is complicated, applying the principles will be complicated, Stenclik acknowledged in his paper.
For example, forecasting any one individual’s potential to supply capacity “is impossible,” Stenclik said. But aggregated data “can assess behavior across masses of customers and derive uncertainty ranges for aggregated DER availability through the law of large numbers to normalize behaviors and make RA more predictable.”
The need to use aggregated DERs for RA will grow in importance, according to Sunrun’s Rauscher. “Many states have very aggressive clean energy goals or mandates, but the markets are not structured to accommodate aggregated DERs and other resources needed to meet them,” he said.
ISO-NE planners have inconclusively modeled multiple new approaches to reliability, including shifting RA to states, imposing a carbon price, creating a clean energy capacity market, and using an energy-only market, Rauscher said. “No matter how the paradigm changes, it is absolutely necessary to harmonize wholesale markets with the reality of the state laws already in place.”
Article top image credit: www.inhabitat.com
The 3 key challenges to expanding the West’s real-time energy market to day-ahead trading
Customer savings and streamlined emissions cuts can come from the Buffett-backed west-wide market planBy: Herman K. Trabish
Utilities and stakeholders in Western states, seeing important benefits in their real-time energy market, are working toward expanding to a regional day-ahead collaboration that could hold much bigger benefits.
The voluntary Energy Imbalance Market (EIM) was launched by PacifiCorp, a subsidiary of Warren Buffett’s Berkshire Hathaway Energy (BHE), and the California Independent System Operator (CAISO) in November 2014 to optimize real time dispatch, according to CAISO. It has generated $919 million in reduced energy costs and other benefits. Now, driven by new Western state renewables and zero emissions mandates, the 11 active participants and 9 new applicants are pushing to expand it to day-ahead trading.
“Generally, EIM entities are helping with the over-supply problem in California by absorbing the excess energy in the solar hours and helping meet California’s morning and evening peaks,” BHE Vice President for Government Relations Jonathan Weisgall told Utility Dive. With a day-ahead energy market, “those reductions in emissions and cost savings could be significantly increased” by optimizing dispatch from limited real-time trading to almost the entire Western energy market.
Western utilities and power providers from Canada to the Mexican border and from the Rockies to the Pacific are working on this voluntary Extended Day-Ahead Market (EDAM). It would expand optimized dispatch and delivery from 5% of the power flows in Western electricity markets to almost 100%.
While there are few apparent declared opponents to the plan, stakeholders must address the three key challenges of the proposed market — its governance, transmission charges across jurisdictions, and guarantees among participants that they will meet their obligations. A first straw proposal is due in early July from CAISO working groups that will suggest the first possible solutions for the West’s diverse stakeholders.
Who, what, why?
Policymakers across the West have rejected efforts by CAISO to organize a formal regional market that would have eliminated cost barriers among the West’s 38 balancing areas where individual jurisdictional entities optimize their own dispatch. California leaders primarily sought to protect the state from federal regulation while other Western leaders have been concerned with protecting their state’s interests from California.
BHE subsidiary PacifiCorp “has achieved customer benefits in the EIM, but rising renewables penetrations represent new levels of variability,” Weisgall added. “The greater resource diversity available through the EDAM will allow utilities optimal dispatch flexibility to meet that increased variability with cost savings for customers.”
The EIM would continue to serve the entities’ real time needs. The EDAM, which would reduce barriers for its voluntary participants in the much larger day-ahead market, is being explored through EIM committees and CAISO working groups by most of the EIM entities.
“This evolution of the wholesale market can have even more benefits by optimizing transactions on a day-ahead basis and more cost-effectively integrating higher levels of renewables.”
VP for Resource Management, APS
“Layered on top of the EIM,” its “day-ahead hourly trading” could add “incremental benefits” like increased customer savings, CAISO Vice President for Market Quality and California Regulatory Affairs Mark Rothleder told a participant group last October.
Leading opponents of previous full regionalization proposals do not oppose EDAM, they told Utility Dive. Sierra Club Beyond Coal Campaign State Strategies Director Bill Corcoran, Marc Joseph, an attorney who represents labor groups, and Matthew Freedman, an attorney with ratepayer advocacy group The Utility Reform Network, agree there is potential value in the plan.
Many details of an organized electricity market, like price bidding and clean energy and greenhouse gas emissions credits, will be settled later. Questions of governance, shared transmission and resource sharing must come first, the EIM entities have decided.
A 2016 study showed a full regional marketplace could potentially deliver savings of $1.5 billion per year from optimized dispatch, shared transmission costs and reduced reserve needs, Brattle Group Principal Hannes Pfeifenberger, who led the study, told Utility Dive. The EDAM benefits would likely “not be as much as those estimated by the 2016 study, but would be more than those from today’s EIM,” he said. The EIM delivered $296.9 million in benefits in 2019.
EIM participants see significant potential benefits in a day-ahead market.
“It is a huge opportunity for Idaho to share its hydro if it is valued appropriately,” Commissioner Kristine Raper of the Idaho Public Utilities Commission (IPUC) told Utility Dive. “There is value to be gained in answering those kinds of complicated questions.”
Arizona Public Service (APS) has already seen benefits in the EIM, APS Vice President for Resource Management Brad Albert agreed. “This evolution of the wholesale market can have even more benefits by optimizing transactions on a day-ahead basis and more cost-effectively integrating higher levels of renewables.”
The first task before would-be EDAM participants is resolving the governance question.
In 2015, a Transition Committee made up of investor-owned utility (IOU), private provider, regulatory, and advocacy group representatives created the EIM governance framework. To broaden representation, they established a Governing Body, a Body of State Regulators and a Regional Issues Forum.
“Both California’s IOUs and other participants were concerned governance would not protect their needs,” CAISO Board of Governors member Dave Olsen recalled. “But the Transitional Committee created a structure that allows the CAISO Board to delegate authority to the EIM Governing Body in a way that satisfied both.”
To design EDAM governance, participants are working through the Governance Review Committee (GRC) created by the EIM Governing Body and the CAISO Board, Olsen told Utility Dive.
“There were changes made to accommodate the EIM and changes are now being contemplated to move EDAM forward,” California attorney Tony Braun, who was a member of the EIM Transition Committee and is a member of the GRC, told Utility Dive.
To move from the EIM’s real-time market to day-ahead regional trading, changes will likely be necessary in CAISO’s day-ahead market rules, an October 2019 CAISO issue paper reported. But the EIM Governing Body’s authority, under which the Transitional Committee built EIM protections, does not extend to day-ahead market rules.
A possible fix would address the fact that EDAM is fundamentally about expanding the EIM to include day-ahead market participation, the CAISO paper reported. CAISO management proposed that its Board approve a “joint authority” structure under which “all aspects of EDAM market design” would be approved only if both the EIM Governing Body and the CAISO Board assent.
“I wouldn’t be a part of the GRC process if I didn’t think that there was a path forward … I started out as a skeptic, but I am impressed with EIM governance.”
Commissioner, Idaho Public Utilities Commission
EDAM “is being driven by EIM entities who see benefits in the optimized use of resources,” former EIM Governing Body Chair Doug Howe, who is also a former New Mexico utility commissioner and currently Director of Western Grid Group, told Utility Dive.
To create governance that protects the interests of California and non-California interests, it is important to distinguish between the authorities of CAISO, which is specific to California’s jurisdiction, and the EIM and the EDAM, which would be multi-jurisdictional.
One solution for EDAM could be a governance framework like the EIM Transitional Committee developed, with adjustments for a larger market and more participants, Howe said. “If an initiative or a proposal would not happen but for the real time market, it goes to the EIM Governing Body first and then to the CAISO Board, but if it applies to the wider day-ahead marketplace, it goes to the CAISO Board first.”
It is “reasonable” that the EIM Governing Body have primary authority, IPUC Commissioner Raper, a GRC member, agreed. But with more participants and resources like the EIM has and EDAM would have, “it has become complicated to know where the bright line is between what is limited to the EIM and what affects the market as a whole.”
She is, however, optimistic about resolving challenges confronting EDAM. “I wouldn’t be a part of the GRC process if I didn’t think that there was a path forward,” she said. “I started out as a skeptic, but I am impressed with EIM governance.”
The GRC’s straw proposal for EDAM governance is scheduled to be announced in early July, according to CAISO. It is also expected to address two other big questions: How to compensate transmission owners and how to set standards for resource sufficiency.
A big question is how EDAM participants will pay for transmission. EIM entitites have used only available transmission at no charge. The much larger day-ahead market will require much more transmission capacity and some form of shared compensation that does not make the traded energy prohibitively expensive.
EDAM will depend on electricity delivered through transmission often built decades ago and operated by transmission owners who depend on revenues from charges to system users. The 5% of the region’s energy flows in the EIM have been transferred on unused transmission provided at no charge, without exceeding transfer capacity limits.
EDAM could include almost all of the region’s energy flows, which means a big leap in scale and new issues for transmission owners.
To EDAM stakeholders, the priorities for transmission charge design are maximizing use of existing transmission on a voluntary basis without disrupting existing scheduling and contracts, CAISO’s February workshop summary reported. EDAM should also “support efficient transmission investment” without interfering with local control and planning, the summary said.
“The sticky points will be around the voluntary participation of the transmission owners. EDAM could push voluntary participation to its limits.”
Director, Western Grid Group
To EDAM entities, the priority is also that “planning and operational control” remain “unchanged,” the summary said. There must also be a balance between “recovery of transmission costs and compensation for transmission utilization” in a way that facilitates and is compatible with existing market transactions.
Discussions to replace differences with compromises are ongoing.
For some transmission owners, the EDAM’s benefits will outweigh the transmission revenue losses, former EIM Governor Howe said. But it is unlikely all participants will be satisfied with any final proposal. “The sticky points will be around the voluntary participation of the transmission owners. EDAM could push voluntary participation to its limits.”
For APS, which owns transmission assets, “there is a lot of ground to cover on the transmission charge issue” and on “transmission owners’ open access obligations,” Albert acknowledged. “We’re trying to move something complicated ahead because it will benefit our customers, but it will not be easy.”
Because entities are aware of the “substantial potential benefits” from EDAM, they are likely to resolve differences on allocation of transmission costs and benefits, Howe, Albert and others said. One approach outlined by Howe and Albert is a small energy charge for each use of the transmission system that is cumulatively enough to provide the needed revenues to transmission owners for the use of their infrastructure but not enough to impede energy trading.
How to share reliability obligations raises similar questions, stakeholders told Utility Dive.
In order for large-scale energy trading between jurisdictions to work, participants must be confident that those committing generation to the day-ahead market have sufficient resources to meet those commitments.
Resource sufficiency is the term used by EDAM entities to represent that commitment. It is different from resource adequacy, which is each state’s responsibility to maintain its own reliability, CAISO Governor Olsen stressed. “Absolute transparency will be needed to ensure that each participant has sufficient resources and no one entity is leaning on another for reliability.”
Rules that guarantee sufficiency are likely to create “tension points” between them on how resource sufficiency is assessed because it also “goes to the larger issue of the EDAM as voluntary,” former EIM Governor Howe said.
Each balancing area’s responsibility to meet its own reliability needs and each state’s control of its own integrated resource planning to manage reliability are CAISO stakeholders’ top priorities for resource sufficiency in any region-wide extended day-ahead energy trading market, a February CAISO Staff resource sufficiency workshop found. Leaving resource adequacy procurements and transmission planning to local regulatory authorities are also priorities.
“[I]f we start with the proposition that a correctly designed market can be broadly beneficial, we owe it to ourselves to work hard to solve these problems. And they can be solved.”
Attorney and member, Governance Review Committee
Transparently meeting individual resource adequacy obligations and maintaining local control of planning are priorities for the entities, too, participants in the February resource sufficiency workshop agreed. Resources made available to other balancing areas must be “real and capable of performing,” and market operations must make resource sufficiency “simple and workable” and prevent “leaning on EDAM for reliability.”
A utility may obtain significant savings and emissions reductions by committing to not run a fossil fuel unit and buying lower cost renewables from another state bid into the next day’s market, APS’s Albert said. “A lot of value can be unleashed like that if it is clear we can rely on those bids. But reliability is something that we will not compromise.”
Resolving the resource sufficiency debate requires “aligning all participants’ approaches to reliability,” he added. “That means synchronizing the adequacy of our portfolios and day-ahead dispatch commitment decisions and transparently communicating business practices across the West.”
The CAISO working groups are developing solutions which may be part of the July straw proposal.
None of the advocates see EDAM in operation in the near term.
Though CAISO’s first straw proposal is expected in early July, it is taking on “the hard stuff first,” former EIM Governor Howe said. “The EIM showed the benefits to be gained and the next step is EDAM, but it is not going to happen fast.”
The straw proposal will be followed by stakeholder comments, Governance Review Committee member Braun said. The committee’s recommendation to EIM and CAISO Governors on governance will likely come in Q1 2021, he added.
“There’s not a bright line for when EDAM will be needed,” he said. Resolving market design differences takes time, and it will take time to implement that market design, “but if we start with the proposition that a correctly designed market can be broadly beneficial, we owe it to ourselves to work hard to solve these problems. And they can be solved.”
Update: An earlier version of this article said the first straw proposal for an Extended Day Ahead Market was due June 15. That timeline has been pushed back to early July.