NERC’s Reliability Issues Steering Committee (RISC) is planning to bring forward the release of its next ERO Reliability Risk Priorities Report — traditionally published in November of odd-numbered years — to August 2021. The biennial Reliability Leadership Summit will be held earlier next year as well — in January – rather than its usual time in March.
Presenting the expected publication schedule to RISC members via conference call on Thursday, Thomas Coleman, director of risk issue management at NERC, said an August release seemed more “timely” than the traditional November publication date. Work on the report is expected to begin in the fourth quarter of 2020 with the production of the risk template and the release of the industry survey to “prioritize identified risks as well as to potentially identify new and emerging risks.”
Results of the survey will form the basis of discussions among industry leaders at the Reliability Leadership Summit. The last summit, held in March 2019, involved more than 130 regulators, utility officials, RTO executives and other stakeholders. (See NERC Chief: No ‘Appetite’ for Expanding Authority.) The format of next year’s summit has not been finalized, but Coleman said that “more than likely” the meeting will be held online.
“I think we can really have a very interactive and productive [summit] virtually,” he said. “We’ve all been on so many different variations of virtual calls, [and] we’ve seen some really innovative and creative approaches, so I feel strongly that we can develop a really meaningful and impactful virtual meeting in the beginning of 2021.”
Risk Framework Goes to RSTC Next Month
RSTC/RISC coordination within the risk mitigation framework. | NERC
NERC Chief Engineer Mark Lauby updated the committee on NERC’s planned risk mitigation framework, which is currently under development with input from the Reliability and Security Technical Committee (RSTC). The committees hope to finish the framework in time to present it to NERC’s Board of Directors at its November meeting.
Development of the framework began last year in hopes of creating a unified, transparent process to help entities choose the best approach to manage various situations. (See NERC Developing Risk Mitigation Framework.) A preliminary framework was created by the ERO Enterprise with input from the North American Transmission Forum and handed off to RISC for further refinement after the February board meeting.
The latest updates to the framework focus on the relationship between the RSTC and RISC in the risk mitigation process, including a flow diagram that breaks down each committee’s responsibilities at each stage. RISC plans to pass the document to RSTC by Aug. 19 for inclusion in the agenda for its meeting next month. Once RSTC members have provided their input, the committees will finalize the document so that RISC Chair Nelson Peeler and RSTC Chair Greg Ford can present it to the board together.
“What we’d like to do, depending on the views of everyone, is ultimately take this to the board as a joint [proposal], so that it kind of puts a little bit more cement around how we identify and prioritize risks and work on risks in a more formal way,” Lauby said.
RISC Charter Updates Accepted
RISC members also voted to approve proposed changes to the committee’s charter and submit them for acceptance by NERC’s board at its November meeting.
The approved edits are largely cosmetic, aimed at replacing outdated language and aligning the charter with those of other NERC committees. However, Jennifer Sterling of Exelon said she was concerned that the committee would have just one representative from the RSTC, as opposed to one each from the Operating, Planning and Critical Infrastructure Protection Committees that the RSTC replaced earlier this year. (See RSTC Tackles Organization Issues in First Meeting.)
Sterling asked if RISC would be able to achieve the same level of coordination with RSTC as its predecessors with fewer shared members. In response, Peeler said that RISC leadership felt one RSTC representative would be enough to maintain communication, especially since the two committees plan to create more formal bonds going forward.
“The purpose of those committee members being on RISC was for them to maintain alignment and bring issues from their committees, not necessarily to be the technical expert of the committee,” Peeler said. “[But] we’re going to have more coordination between RSTC and RISC formalized … in the framework.”
WECC is soliciting stakeholder comments on a draft strategic plan that seeks to build on NERC’s ERO Enterprise Long-Term Strategy while adding a Western flavor.
| WECC
“WECC took a hard look at the ERO Long-Term Strategy (LTS) and, with input from the board, made some really intentional decisions about what concepts made sense for incorporation and further expansion … to reflect WECC’s unique profile and perspective,” Jordan White, WECC vice president of strategic engagement, told the organization’s Member Advisory Committee Wednesday.
NERC’s Board of Trustees approved a revised ERO Enterprise LTS in December. That plan calls on the regional entities to incorporate four “value drivers” into their practices, including using innovative, risk-based programs; seeking top talent; and balancing industry collaboration with independence and objectivity. (See NERC Plans Reviewof Supply Chain Standards.)
The NERC LTS also identified five key focus areas for REs in coming years, including expanding its risk-based focus in all areas; taking steps to mitigate emerging reliability and security risks; building a strong Electricity Information Sharing and Analysis Center (E-ISAC); strengthening engagement across North America; and “captur[ing]” continuous improvement opportunities.
WECC’s draft LTS riffs off NERC’s five focus areas with variations of its own:
Innovate and expand risk-based focus in all standards, compliance monitoring and enforcement actions. WECC says it will provide leadership and expertise in the development of ERO standards and draw on “rich stakeholder expertise in the West” to evaluate and develop regional reliability standards or variances “to assure they carefully consider the unique characteristics of the Western Interconnection.”
Assess and initiate action to mitigate known and emerging risks to the reliability and security of the Western Interconnection. WECC promises continued collaboration with the ERO Enterprise in developing special assessments and studies while ensuring those efforts are informed by Western viewpoints. It will also supplement those assessments with “Western-focused” work when necessary.
Strengthen engagement with the reliability and security community in the Western Interconnection. This focus area reflects WECC’s recent push to ramp up its engagement with regional stakeholders through “proactive outreach and communications with key state and provincial regulatory, legislative and policy bodies and associations to identify drivers of change.” WECC will reach out to share relevant reliability impact information with industry decision makers as they “drive change” across the West. It also intends to share the region’s “specialized and localized” point of view on national reliability and security matters.
Seize opportunities for effectiveness, efficiency and continuous improvement. WECC will work to ensure it has the budget and staff to follow through on its reliability and security mission. It will also establish annual goals for organizational performance and share progress with stakeholders through a corporate scorecard.
Build the capability and culture that enable WECC to deliver on its critical reliability mission. This entails WECC becoming an “employer of choice” that attracts “the right talent to deliver on its performance objectives.” This focus area also emphasizes the importance of WECC’s “invented future,” during which it builds strong relationships to collaborate with industry on implementing risk-based concepts rather than just enforcing compliance with standards. (See WECC Seeks to ‘Invent Future’ with RA Forum.)
WECC will hold an Aug. 11 webinar “where we plan to do a deeper dive into the long-term strategy and get stakeholder input,” White said. Stakeholders are asked to comment on the plan by Aug. 19. WECC management hopes to get board approval for the LTS in September.
“Assuming that the final long-term strategy is approved with all of the stakeholder feedback, et cetera, by the board at the September meeting, we plan to hold an interactive forum at the annual meeting to increase stakeholder engagement and understanding of the long-term strategy,” he said.
WECC will hold its annual meeting virtually this year on Sept. 10-11.
FERC on Tuesday found that Idaho Power had satisfied the commission’s standards for market-based rate authority and terminated a Section 206 proceeding it had ordered last September to find out if the utility was exercising market power in its balancing authority area (ER10-2126).
The proceeding was meant to determine if Idaho Power could continue charging market-based rates in its BAA.
The company’s market-power analysis, initially submitted in June 2019, had passed the pivotal supplier and wholesale market share screens in the Avista, Bonneville Power Administration, Nevada Power, NorthWestern Corp., PacifiCorp-East and PacifiCorp-West BAAs and in CAISO’s Energy Imbalance Market. But it failed the wholesale market share indicative screen in one season in its own BAA.
Based on the results, FERC ordered Idaho Power to show cause within 60 days why the commission should not revoke the company’s market-based rate authority in its BAA.
Lower Salmon Dam | Idaho Power
Responding in November, Idaho Power said its updated market power analysis, which included a delivered price test (DPT), rebutted the presumption of horizontal market power in its BAA.
“As the commission has previously explained, the DPT analysis identifies potential suppliers based on market prices, input costs and transmission availability and calculates each supplier’s economic capacity and available economic capacity for each season/load level,” FERC said. “The results of the DPT are used for pivotal supplier, market share and market concentration analyses.”
The DPT calculates market concentration using the Hirschman-Herfindahl Index (HHI). “An HHI of less than 2,500 in the relevant market for all season/load levels, in combination with a demonstration that the applicants are not pivotal and do not possess more than a 20% market share in any of the season/load levels, would constitute a showing of a lack of horizontal market power, absent compelling contrary evidence from interveners,” FERC explained.
Under the available economic capacity measure, which factors the utility’s own load into the calculation, Idaho Power’s HHI score was less than 2,500 in all 10 season/load levels. But under the economic capacity measure, its HHI exceeded 2,500 in all 10 season/load levels and “thus Idaho Power fails the market concentration test in every season/load level,” FERC said.
However, FERC noted its prior rulings had found that “failure of either the economic capacity or available economic capacity analyses does not result in an automatic failure of the test as a whole. The commission weighs the results of the economic capacity and the available economic capacity analyses and considers the arguments of the parties.”
“As the commission explained in Order No. 697: ‘[I]n markets where utilities retain significant native load obligations, an analysis of available economic capacity may more accurately assess an individual seller’s competitiveness, as well as the overall competitiveness of a market, because available economic capacity recognizes the native load obligations of the sellers,” FERC wrote. “On the other hand, in markets where the sellers have been predominantly relieved of their native load obligations, an analysis of economic capacity may more accurately reflect market conditions and a seller’s relative size in the market.’”
Given Idaho Power’s native load obligations, FERC found the available economic capacity measure — under which its HHI score was consistently less than 2,500 — more accurately reflected conditions in Idaho Power’s BAA.
“Based on the above discussion, there is no further need for the Section 206 proceeding instituted in Docket No. EL19-87-000,” FERC said. “Accordingly, we will terminate this Section 206 proceeding.”
The company formerly known as Vistra Energy — Vistra Corp. as of July 2 — boosted its second-quarter cash flow by 30% over 2019 and told financial analysts Aug. 5 that the best may be yet to come.
Vistra delivered earnings before interest, taxes, depreciation and amortization of (EBITDA) of $929 million, based on net income of $164 million. The company had an EBITDA of $717 million and net income of $354 million during last year’s second quarter.
Vistra uses adjusted EBITDA as a measure of performance, saying it improves visibility to both net income prepared in accordance with GAAP and adjusted EBITDA.
Luminant’s Odessa-Ector gas plant stands ready for possible scarcity pricing later this summer. | Luminant
CEO Curt Morgan reminded analysts during a conference call that “much of the Texas summer shows its teeth in August and September.” He noted that while Vistra’s generating subsidiary, Luminant, has not yet been able to take advantage of scarcity prices in the ERCOT market, last August saw 72 15-minute intervals over $1,000/MWh and 12 intervals reaching the $9,000/MWh cap.
“All it takes is one week of hot temperatures and either low wind output or an unplanned outage for scarcity pricing to materialize,” Morgan said.
At the same time, he warned investors about EPA’s recent regulatory revisions for utilities’ disposal of coal ash. (See “EPA Changes Closure Requirements in Coal Ash Rule,” Federal News.)
“Our evaluation suggests there are several coal plants, especially in PJM, that are under pressure due to this rulemaking,” Morgan said.
Vistra’s share price lost 50 cents during the day, closing at $18.26 on the New York Stock Exchange.
A new study finds that Bureau of Ocean Energy Management (BOEM) offshore wind area lease auctions over the next two-and-a-half years could initially pump $1.7 billion into the U.S. Treasury while potentially creating 80,000 jobs and $166 billion in capital investment through 2035.
“We’re talking about five lease areas, offshore New York, North Carolina, South Carolina, California and Maine, and these areas could unlock tremendous energy and economic potential,” Erik Milito, president of the National Ocean Industries Association (NOIA), said at a press conference Tuesday.
The report shows OSW development supporting approximately 80,000 jobs annually from 2025 to 2035. | Wood Mackenzie
NOIA commissioned the study by research group Wood Mackenzie with three other groups: the American Wind Energy Association (AWEA), the New York Offshore Wind Alliance (NYOWA) and the Special Initiative on Offshore Wind (SIOW) at the University of Delaware.
“From the NOIA perspective … there is a very strong synergy between offshore oil and gas and offshore wind … and the same shipbuilders, heavy lift vessel operators, steel fabricators and other companies who built the Gulf of Mexico oil and gas business stand ready to lend their expertise to the American offshore wind industry,” Milito said.
Feng Zhang, managing consultant for Wood Mackenzie’s power and renewables division, said the study mainly looked at areas from the New York Bight and south, plus California, but that interest was also “very high” in possible call areas in the Gulf of Maine.
“From the study, we found that if the relevant policy can be put in place, if BOEM and other industry parties can act very quickly, then potentially 2 million acres of federal waters in those areas can go to auction as soon as 2021 and 2022,” Zhang said.
Jump Starter
Additionally, the findings indicate that new offshore wind leases could be a short-term way to jump-start recovery from the economic slowdown caused by the coronavirus pandemic, Zhang noted.
The study found that investment in the country’s offshore wind industry will total $17 billion by 2025, $108 billion by 2030 and $166 billion by 2035.
“From 2022 to 2035, capital investment of $42 billion will go to turbine manufacturers and the supply chain, $107 billion will go to the construction industry and $8 billion will go to the transportation industry and ports. Annual capital investment for operations and maintenance activities will increase to $2.4 billion in 2035,” the study said.
Long-term, new OSW projects will provide 28 GW of new clean energy resources to power 20 million households and support 20,500 jobs annually for decades beyond 2035, the study found.
The other study sponsors issued statements lauding the economic and environmental benefits of OSW development.
“States along the eastern and western seashores have a massive domestic clean energy resource and many states have set ambitious offshore wind goals to reap the economic and environmental benefits that offshore wind offers but cannot achieve those goals with existing leases,” said NYOWA Director Joe Martens. “It’s time for the federal government to act with the same urgency as the states.”
“We’re on the cusp of a rare opportunity, but the U.S. remains far behind other countries in harnessing offshore wind technology,” said Laura Morton, AWEA senior director of offshore wind. “It’s time for us to unleash this abundant domestic energy source that will deliver tens of thousands of new jobs, revitalize coastal ports and expand manufacturing opportunities to reap major economic and environmental benefits.”
“Offshore wind development can be a major part of the solution to our country’s most pressing energy needs and our country’s most immediate economic woes,” said Nancy Sopko, executive director of SIOW. “Unleashing the potential of offshore wind power through immediate and consistent auctioning of new lease areas can help the United States rebound from the greatest economic downturn in our nation’s history.”
Exelon CEO Chris Crane on Tuesday apologized for subsidiary Commonwealth Edison’s involvement in a bribery scandal and said he may be forced to shut down the company’s Illinois nuclear plants without favorable state legislation.
In July, ComEd agreed to a $200 million fine with the Illinois U.S attorney’s office to settle allegations it bribed the state House of Representatives’ speaker in return for legislation that increased the company’s earnings and bailed out its money-losing nuclear plants. Under the Deferred Prosecution Agreement, the bribery charge will be deferred for three years and then dismissed, as long as ComEd continues to cooperate with “ongoing investigations of individuals or other entities.” (See ComEd to Pay $200 Million in Bribery Scheme.)
“We’ve taken robust actions to identify and address deficiencies, including enhancing our compliance governance, to prevent this conduct,” Crane said during a conference call with financial analysts. “We apologize for the past conduct, which did not live up to our values. These new policies will ensure it won’t happen again.
“We’re extremely disappointed with the seriousness of the past misconduct,” he said, listlessly reading his prepared comments. “We know many stakeholders understandably feel the same disappointment. We will take every possible step to earn back the confidence and trust we have lost. This will not happen overnight, and it will be a formidable task, but we’re resolved to get there.”
Crane said Chicago-based Exelon must restore the trust that “has been eroded” while, at the same time, working through legislative strategy in Illinois to help its nuclear plants earn capacity market revenue.
“It’s very critical for us to get it done,” he said, noting his “analytic folks” have a “strong sense” that Exelon’s nuclear units will not clear the next PJM Base Residual Auction.
“Some are uneconomic at this point right now, and some may become more uneconomic,” Crane said. “If we can’t find a path to profitability, we’re going to have to shut them down. We will not run plants and lose free cash flow or earnings on assets that are not supporting themselves. … We will not let the balance sheet [be] further [deteriorated] by non-profitable assets.”
Exelon has lost 14.7% of its stock value since the year began.
The company reported a “strong quarter” with earnings of $521 million ($0.53/share). A year ago, the company had earnings of $484 million ($0.50/share).
Exelon’s operating earnings of $0.55/share beat analysts’ expectations of $0.42/share, as gathered by Zacks Investment Research. The stock price gained 76 cents on the NASDAQ, closing at $38.75.
MISO’s participation model for electric storage resources needs a final edit before FERC declares the grid operator fully compliant with Order 841, the commission said this week.
FERC on Monday ordered MISO to remove or defend its requirement that distribution utilities and load-serving entities report real-time grid injections and withdrawals. FERC said MISO couldn’t impose reporting obligations on distribution utilities or LSEs because those companies aren’t party to its new pro forma storage participation agreement. FERC said MISO might require data reporting from companies that might not have “any relationship” with the grid operator (ER19-465).
“This reporting requirement is also unnecessary because MISO proposes to require the electric storage resource to report the same information,” the commission said.
FERC said it otherwise approved of MISO’s plan to make market participants responsible for meter installation, ownership, meter-data quality and “periodic testing of metering and related equipment.” The commission also found no problem with MISO’s requirement that storage owners report hourly real-time injections and withdrawal volumes at commercial pricing nodes or to estimate hourly injections and withdrawals if the energy storage resources don’t have a meter at a node.
| Connexus Energy
FERC in November found that MISO’s model largely complied with Order 841 but lacked detail about metering and accounting practices for distribution-connected and behind-the-meter ESRs. (See Storage Plans Clear FERC with Conditions.)
FERC’s latest order, however, rejected a group of Midwestern transmission-dependent utilities’ ask that MISO’s new pro forma agreement not be applicable to ESRs with on-site generation.
“Order No. 841 defines an ‘electric storage resource’ as a resource that can receive energy from the grid and store it for later injection back onto the grid. This definition does not specifically include or exclude, or otherwise discuss, electric storage resources that have on-site generation,” FERC said.
The commission also declined the Midwestern group’s request that it order MISO to make storage resources pay the Multi-Value Project (MVP) transmission charge. The charge funds the grid operator’s 2011 MVP transmission expansion portfolio and is allocated on a load-ratio basis to wholesale energy purchases. FERC agreed with MISO that storage resources should be exempted from the charge “because they do not consume energy as an end-use.”
“Even if the Tariff language and rate structure that existed prior to Order No. 841 allowed the assessment of the MVP charge to [ESRs] based on their monthly net actual energy withdrawals in a manner analogous to load, [ESRs] would still largely avoid the MVP charge because their withdrawals from charging would be mostly offset or netted by their discharging injections,” the commission wrote.
Finally, FERC accepted MISO’s explanation that ESRs should be excluded from qualifying as fast-start resources. The ISO said storage resources, as “offline energy-limited resources,” would “depress prices because they may be less feasible and less available due to state-of-charge management by the market participant.”
MISO has until mid-2022 to implement its ESR participation plan, as it will first have to build a new market platform.
FERC on Monday accepted most provisions in NYISO’s second attempt to comply with Order 841, which requires RTOs and ISOs to remove market barriers for energy storage resources (ESRs).
The decision specifically accepted proposed Tariff revisions to subject ESRs to transmission charges, effective no later than Sept. 30, but ordered the ISO within 90 days to clarify its proposed exemptions to such charges (ER19-467). The commission faulted the initial compliance filing for failing to apply those charges to ESRs when they are charging in the wholesale market for later retail sale but not providing services to the grid.
The commission also deemed NYISO’s Jan. 21 request for rehearing to be denied by operation of law.
Issued in 2018, Order 841 requires market participation rules to recognize the unique physical and operational characteristics of storage resources. The commission last December partially accepted NYISO’s compliance filing but faulted the ISO for lack of details on its metering methodology and accounting practices for ESRs located behind a customer meter. (See FERC Partially Accepts NYISO Storage Compliance.)
In its second compliance filing in February, the ISO proposed not to assess transmission charges to ESRs when the resource receives a real-time operating reserves schedule; receives a real-time regulation service schedule; is operating and is a qualified supplier of voltage support service; or is dispatched as out-of-merit to meet New York Control Area (NYCA) or local system reliability.
FERC accepted those provisions, but required NYISO to provide clarifications, saying that because these services are typically scheduled on top of a resource’s base energy schedule, it is unclear what portion of a resource’s megawatt withdrawals the ISO proposes to exempt from transmission charges, in particular of withdrawals during an interval when the resource is self-scheduled at a fixed megawatt quantity.
Pumped up
In its request for rehearing, NYISO argued that its proposed approach to not assess transmission charges aligns with its existing rate structure for transmission charges assessed to resources in the NYCA that withdraw energy at a node for later injection into the grid.
Specifically, NYISO said for more than 20 years it has applied a separate rate structure for transmission charges applicable to the 1,134-MW Blenheim-Gilboa Hydroelectric Power Station in the Catskills, a pumped storage facility owned by the New York Power Authority. The ISO argued that the station is located at a single generator bus that pays the nodal locational based marginal price (LBMP) to withdraw energy as a “negative injection” for later injection back into the grid.
NYISO wants to exempt resources like NYPA’s 1,134 MW Blenheim–Gilboa Hydroelectric Power Station in the Catskill Mountains from Order 841 transmission charges.
NYISO sought to apply the same separate rate structure to all nodal ESRs in in its jurisdiction and said that under Order 841, when such resources are marginal in the ISO’s dispatch of energy, loads in the NYCA would effectively be paying the related charges twice — once as part of the energy component of LBMP and again when NYISO and the relevant New York transmission owner assess charges to the loads.
But the commission said it was not persuaded by NYISO’s request for rehearing and continued to find the ISO has not demonstrated, as required in Order 841-A, that its proposal not to apply transmission charges to all ESRs is reasonable given how it assesses transmission charges to wholesale load under its existing rate structure.
“As a general matter, NYISO assesses transmission charges to all wholesale load, and it only declines to assess transmission charges to the withdrawals by one specific pumped storage facility when that facility is participating under the energy limited resource (ELR) model,” the commission said. “Thus, NYISO’s proposal not to apply transmission charges to any energy storage resource is not consistent with or reasonable given its existing rate structure, as contemplated by Order No. 841-A.”
The commission also said that NYISO’s double payment argument “is, in essence, a late-filed request for rehearing of Order No. 841 and is statutorily barred. Notwithstanding this procedural flaw, NYISO’s argument is also unpersuasive on the merits.”
Two different transactions occur, the commission said: “One that entails the electric storage resource purchasing charging energy at wholesale from the RTO/ISO market, and another that entails wholesale load purchasing energy from the electric storage resource via the RTO/ISO energy market. As such, we find that it is reasonable to apply transmission charges to both the electric storage resource and the loads associated with those separate transactions and for load to ultimately pay the two transmission charges.”
NYISO also argued that FERC’s rejection of its proposal was inconsistent with the commission’s acceptance of a CAISO proposal to exempt all ESRs from transmission charges when charging, consistent with CAISO’s existing rate structure.
Not so, said the commission.
“Unlike CAISO’s non-generator resource model, which was designed for electric storage resources, NYISO’s ELR model is designed for and primarily used by generators. Indeed, NYISO withdrew its ELR model from consideration for compliance with Order No. 841 because, according to NYISO, the ELR model could not accommodate withdrawals from ESRs.”
NYISO’s treatment of one pumped storage facility under the ELR model is thus a limited exception and not representative of how the ISO assesses transmission charges to wholesale load under its existing rate structure, the commission said.
Evergy has decided to stay single after dalliances with several potential acquisition partners, according to a published report.
Quoting “people familiar with the matter,” Bloomberg said Tuesday that the Kansas City-based company has decided to remain independent. Evergy has decided it can create more value for shareholders through a new operating plan, which had been in development while the company explored a possible sale, the report said.
The plan’s details are expected to be shared with financial analysts Wednesday when Evergy holds its quarterly earnings call before the market opens.
Evergy’s subsidiaries in Kansas, Missouri. | Evergy
Evergy’s share price plunged 13.4% after the Bloomberg story broke, from $62.81 to $55.40. It was trading at $55.79 as the market neared its close.
Evergy has been under pressure from activist investor Elliott Management, which took a $760 million stake in the company and has pushed it to shake up its management team. Evergy said in March that it had reached an agreement with Elliott to establish a new strategic review committee to explore ways to improve shareholder value. (See NextEra Said to be Eyeing Evergy as Acquisition Target.)
Ameren, American Electric Power, CMS Energy and NextEra Energy are among those linked to Evergy as potential buyers.
Evergy, an SPP member, was created in 2018 through a merger between Kansas City Power and Light and Westar Energy. It serves 1.6 million customers in Kansas and Missouri.
CAISO’s proposal to develop new capacity products through its day-ahead market enhancements (DAME) initiative could radically transform California’s resource adequacy landscape while not yielding expected benefits, a key skeptic of the plan said last week.
“I agree that in the vast majority of situations having a market price is an extremely valuable thing [and] I’m not trying to come down on either side of this one right now. I’m just saying it’s a philosophical change in the way these [RA resources] are being paid that we should think about,” Mike Castelhano, an analyst with the California Public Utilities Commission, said during discussion of the proposed capacity products at a CAISO Market Surveillance Committee (MSC) meeting Thursday.
The ISO launched the DAME effort earlier this year to expand its day-ahead market with two new nodal product offerings that would significantly alter market operations:
a reliability capacity (RC) “up/down” product to help the ISO match its net load forecast (the load forecast minus the variable energy resource forecast) with sufficient non-VER supply for one-hour intervals; and
an imbalance reserves (IR) product procured for 15-minute intervals “to provide flexible capacity to accommodate the increasing uncertainty and variability of real-time net load.”
Both products would be offered on a nodal basis, an approach CAISO thinks will best guarantee those supplies will be available when and where they’re needed to ensure flexibility on a grid increasingly dependent on VERs. The DAME straw proposal envisions co-optimizing procurement of both new products — along with day-ahead energy and ancillary services — to improve scheduling efficiency.
Graph illustrates price differences for the same intervals among CAISO’s day-ahead (blue), hour-ahead (orange), 15-minute (green) and 5-minute markets (purple). The ISO’s DAME initiative is particularly aimed at closing the discrepancies between day-ahead and 15-minute prices. | CAISO
That new process would replace the existing residual unit commitment (RUC) process for ensuring resource sufficiency, in which the day-ahead market procures the incremental capacity needed to meet reliability requirements after the ISO has run its co-optimized integrated forward market (IFR) for day-ahead energy and ancillary services. The incremental capacity obtained through RUC represents the delta between what the IFR has cleared from economic bids and “the amount needed for reliability based on the net demand forecast and potential uncertainty,” the ISO notes in the straw proposal.
“The disadvantage of this sequential RUC process is that the capacity it procures is not co-optimized with the resource commitment and energy schedules produced by the integrated forward market,” CAISO said in explaining the move to the new model.
‘Vanilla’ RUC vs. Spot Market
While CAISO has counterposed two methods for compensating suppliers of the two new products, it clearly favors one option over the other.
Under the “vanilla RUC model” (as ISO Market Design Policy Specialist James Friedrich put it), resources that have been awarded contracts under the CPUC’s RA program could offer into the market at zero price and forego being paid market clearing prices for RC and IR. In that scenario, CAISO would assume the prices of RA contracts — which subject holders to a must-offer obligation (MOO) in the ISO market — “would, in part, reflect owner expectations about magnitudes and frequency of short-run costs incurred to provide RC/IR.”
According to the ISO, the RUC model approach to compensating the new capacity products would be the least disruptive to California’s current RA system because it wouldn’t require renegotiation of existing RA contracts, changes in CPUC rules around cost recovery for RA assets or revisions to CAISO’s MOO Tariff provisions. It would also avoid the need to mitigate market power for RC/IR offers.
Those advantages notwithstanding, CAISO — and the MSC — are advocating implementing a “spot market model” as much as possible to compensate providers of the new capacity products, with the hope that short-term market offers will more precisely reflect variable costs for making capacity available, including natural gas costs and the opportunity costs of not bidding into the real-time market. That arrangement would provide suppliers a stronger incentive to make resources available, according to the MSC.
Use of that model would also eliminate the must-offer obligation for contracted RA resources, which should reduce the number of zero-price offers and increase clearing prices (while also increasing the risk of double-payment before RA contracts can be renegotiated, CAISO acknowledged). That would have the upshot of opening up California’s capacity market to non-thermal resources, helping the state achieve its ambitious carbon reduction goals, one MSC member noted.
“One of the characteristics of the current design is that … demand response can’t compete to provide RUC capacity because thermal RA units are free,” said the MSC’s Scott Harvey. “And they’re not really free, but it gets rolled into the RA price, so you don’t see a separate price signal for [whether] demand response [could] provide this RUC capacity, which is really back-up capacity that we don’t need but we want to have in reserve in case we do need it. And that’s probably an ideal role for demand response … so that’s another long-run goal that could be achieved if we make this change.”
MSC member Jim Bushnell said a long-term focus of the committee is providing “short-run marginal incentives to reward units that provide truly valuable reliability capacity” and incentivizing resource availability.
“The problem with RA has been that we don’t know a year in advance and a month in advance exactly when and what types of units provide what type of value. That’s constantly changing, so the importance for short-run incentives is large here,” he said.
CPUC Concerns
CPUC’s Castelhano said he understood Harvey’s concerns about DR being unable to function as RA capacity in the CAISO market. But Castelhano noted that the RA zero-bid requirement is a CPUC capacity designation rule and not “really a RUC rule.” He cautioned CAISO against making changes that could alter the zero-bid practice in the wholesale market or pushing to revise market rules in a way that would allow DR to function as RA in California.
“The rules for RA and DR are not as well-developed, and that’s a process that’s ongoing, and I think we have to recognize that’s not something that should change at the CAISO necessarily,” Castelhano said.
“I wasn’t arguing for a change in the rules regarding DR that is RA capacity,” Harvey said, clarifying that his focus is on enabling DR — “whether or not it’s RA capacity” — to compete to provide RUC. “That’s the CAISO issue.”
Castelhano also called out CAISO for not discussing how transformative the ISO’s changes could be for California RA, potentially transforming the program from a structure based on contracts to one reliant on a spot market.
“Sure, it gets the costs out of the RA contracts, potentially, but it also then pays a market mechanism-based price to everybody that clears in that market, whereas right now the RA costs are individual” and cost based, said Castelhano. A system based on a clearing price could allow some suppliers to earn inframarginal rents — where a supplier gets paid above its costs in an otherwise competitive market.
MSC Chair Ben Hobbs acknowledged that consumers could benefit if the utilities contracting for RA hold prices down because of monopsony market power and pass on those savings. But he said it is not clear that would happen because visibility into RA contract prices “is not exactly a strong point” in California’s market.
“RA contracts tend to be near some market-clearing level, but from an efficiency point of view, hearkening all the way back to the early days of the California market of pay-as-bid versus market-clearing price, folks who have been on the MSC have tended to favor [a] single market-clearing price for its transparency and incentives,” Hobbs said. “But you might have a point. If the utilities can price-discriminate on RA perhaps there will be less ability to do that in the future, which might conceivably increase what consumers pay and provide more of the inframarginal rents to resources.”
Castelhano also questioned CAISO’s presumption that the new capacity products would reduce some of the “guesswork” behind calculating the costs of RA contracts because income for RA resources would be based on actual short-run costs rather than on a longer-term estimation of those costs.
“My speculation is that it would go very much in the opposite direction because right now part of the RA contract depends on one variable stream of income from sales into the ISO market, and you’re going to create another possibly more variable stream of income,” he said.
Hobbs countered that the proposal’s provision allowing RA resources to buy out their must-offer obligation or bid costs in the ISO market would reduce the cost risks of having a fixed MOO negotiated far in advance of potential deliveries.
“I guess that needs some more analysis, but I don’t agree with what you’re saying there,” Hobbs said.
Castelhano concluded with “a really big concern” that CAISO is considering limiting the participation of energy storage resources in the imbalance reserve markets. He noted that the CPUC’s integrated resource planning process is assuming that storage resources will play a key role providing flexibility needed to integrate variable renewables.
“If [storage] resources are not able to participate in this imbalance reserve market, then I’m very concerned about that,” Castelhano said. “If we’re paying hourly dispatchable resources instead of the stuff that can move really fast, then that’s another concern.”
