Stakeholders will keep a close eye on MISO’s attempt to improve a customer market portal, the RTO’s Steering Committee decided during a Wednesday conference call.
The committee instructed the Market Subcommittee to monitor the RTO’s progress on using more up-to-date information in the Customer Connectivity Environment (CCE).
The nonpublic CCE provides MISO members access to the day-ahead and real-time market user interface, meter data upload applications, and the financial transmission rights and auction revenue rights system.
DTE Energy submitted a complaint on connectivity issues and the state of the data upkeep in the CCE, saying database updates are not being performed regularly.
DTE Manager of Wholesale Market Development Nick Griffin said market participants and MISO software vendors “unnecessarily waste time and resources” during new software testing, “facing extended testing times and elevated costs for software implementations.”
Griffin said during MISO’s rollout of five-minute market settlements in 2018, a “lack of relevant meter data, awards, offers, dispatch instructions, etc.” resulted in a less-than-ideal member testing of the new settlement system.
“We have experienced ongoing production-submission incidents, including unit offers, demand bids and meter data submissions,” DTE said, adding that the problems “reduce confidence in CCE.”
DTE said the problem requires “immediate attention,” especially considering that MISO is refreshing its IT systems as part of its ongoing market platform replacement.
MISO’s Jim Kaminski said staff are aware of the problem and “actively working on the issue.”
“This is quite an issue that we need to take a look at,” SC Chair Tia Elliott said.
SC Mulls Consultant Transparency
The SC may also delve into how forthcoming consultants should be about who they represent during MISO committee meetings.
At the beginning of the year, committee leaders began enforcing a rule that all stakeholders making comments during meetings first identify themselves and who they’re representing before speaking.
The Planning Advisory Committee has reported that some consultants participating in meetings are reluctant to reveal their clients before offering comments or criticisms on MISO presentations.
“There are some individuals in some meetings that are making some rather large requests of MISO. … It would be nice to know who they’re making those requests on behalf of. I think that’s something important to know,” WEC Energy Group’s Chris Plante said.
“I think MISO’s meetings need to be open and fair. And this kind of behavior might not result in fair meetings because of hidden clients … trying to influence the process,” Minnesota Public Utilities Commission staff member Hwikwon Ham said. “I am biased towards the state regulatory sectors and the Minnesota commission. I do not deny this. I want the same of others so I can interpret their opinion in certain matters.”
Elliott said consultants could be bound to nondisclosure agreements. Such consultants also could be representing just one MISO stakeholder or several, she said.
The committee would schedule time at its March 25 meeting during MISO Board Week in New Orleans for a deeper discussion on the issue, Elliott said.
SEATTLE — Preliminary findings from a Western Electricity Coordinating Council study indicate that inclusion of day-ahead trading in the Energy Imbalance Market will yield reliability benefits that outweigh any expected risks for the Western Interconnection.
Among the benefits: increased coordination across a broader geographic area; uniform application of advanced scheduling processes over multiple balancing authority areas; and improved positioning of resources for real-time operations.
The working group developing the study shared its initial impressions Wednesday at a meeting of WECC’s Market Interface Committee (MIC).
Working group member Alaine Ginocchio, a policy analyst with the Western Interstate Energy Board, explained the report will be tightly focused on providing a “qualitative” assessment of the reliability impact of incorporating CAISO’s proposed extended day-ahead market (EDAM) into the EIM. It will not examine potential economic benefits or cost savings from the change, she said.
“We’re going to describe changes in the day-ahead processes and the potential impact those processes could have on reliability,” Ginocchio said. The group is examining reliability impacts through the lens of operations; ancillary services; resource sufficiency; transmission and seams operations; and congestion management.
The report’s analysis assumes that existing BAA boundaries and NERC-related responsibilities will remain intact and that CAISO will not take control of transmission facilities. It also assumes that integrated resource planning, resource adequacy procurement, and transmission planning and investment decisions will continue to fall to individual BAAs and their state and local regulators.
Ginocchio said the intended audience for the report is state policymakers, utility regulators and WECC’s Board of Directors. “You are not our target audience,” she told MIC members.
And she offered one important caveat: The report will be released before the conclusion of CAISO’s EDAM stakeholder initiative, which will not even produce a straw proposal until late March.
“We’re out ahead of the market design here,” Ginocchio said, clarifying that the working group has no special insights into what the ISO will produce from the EDAM initiative.
“We didn’t want there to be confusion as we go through this that somehow we have some inside information about what the potential design is and that’s what we’re analyzing. We do feel like there’s enough public information right now to make some high-level assumptions about this market framework,” she said.
Those assumptions include:
Participation in the day-ahead market will be voluntary for EIM participants.
The market will rely on security-constrained unit commitment, a full network model and LMPs.
Ancillary services will be offered in the market along with energy.
A resource sufficiency evaluation will be required before trading in the market, although the report will make no assumptions about the design of the test.
The EDAM will operate alongside the existing bilateral day-ahead market.
CAISO will not be offering a centralized capacity market.
Paradigm Shift
Jason Smith, senior manager of operations at Xcel Energy and a participant in the study, told the MIC the WECC report will go into “good detail” about the three trading “paradigms” currently in play in the West: a highly centralized CAISO, EIM BAAs and non-EIM BAAs.
“The things that the three types of BAAs are doing [before real-time commitment] are really the same process at a high level,” Smith said.
Before committing units, he said, “you’ve got to assess the situation depending on what your constraints are going to be,” including transmission limits, ancillary service obligations, load, and physical requirements for firming up variable energy resources.
A number of factors go into the decisions, including the cost of buying power in the market versus self-supply, opportunities to sell and market positioning.
“And we don’t just make those decisions in the day-ahead and send those guys home. It’s fully reoptimized in any of those scenarios all the way up until real time,” Smith said.
CAISO’s centralized market provides the benefit of coordinated submission of unit data and a single decision-maker dispatching across a wide area. And the ISO requires a lot more unit-specific data compared with the bilateral market, including resource commitment details and transmission availability. “All that information has to come into the market operator in sufficiently advanced time so those decisions can be made,” Smith said.
“There’s a lot of scrutiny on the data when we make it financially binding. I’ve always said, once you make the data financially impactful, the data seems to get better really quickly,” he said.
Smith said the working group had some difficulty in pinpointing the EDAM’s potential reliability benefits around transmission coordination.
“In going through this report, we found it was very, very difficult to carve reliability versus economic benefits.
“We would discuss that what are we doing in the day-ahead [is] … reducing [commitment] down to an efficient level,” he said. “Efficient means less resources online, so is that an economic benefit or a reliability benefit?”
But some reliability benefits are readily apparent, including better positioning for real time and improved visibility across the system, helping BAAs avoid “committing their own resources in a vacuum.”
An EIM day-ahead market could also reduce the region’s deployment of flexible resources needed to firm up the output from variable renewable resources.
“We use a phrase: ‘complementary diversity.’ That’s just reflecting solar decreasing in the afternoon as wind is starting to increase,” Smith said.
Risk/Benefit Trade-off?
But the study also points to possible risks, including the development of new seams between different market footprints. That could lead to a breakdown in communication and coordination as utilities inside and outside the EIM unknowingly vie for the same resources.
“We can’t have two entities looking at the same transmission capability and deciding that it’s available for use in the day-ahead. That has to be coordinated,” Smith said. “And congestion management is going to fall out of that. That has to be managed between and across seams.”
Smith also pointed to the working group’s concern about how EIM day-ahead scheduling will allow participating transmission operators to push transmission lines to the edge of their capacity.
“There are probably going to be parts of the transmission system that are run all the way up to their limits. Depending on your point of view, do you consider that a benefit or a risk?” Smith asked. “I mean, we’re more fully utilizing it, but yet we’re staying below any reliability considerations. Economically, that’s pretty apparent, but on the reliability side, it can get a little more gray.”
The same goes for changes that will tighten up the resource commitment process.
“You [currently] have a bunch of entities committing inefficiently, which may lead to excess capacity on the system at a given time,” Smith said. “How much reliability benefit has that given us? How much cushion has that been giving us that we’re going to decide — on an economic basis — to kind of give away?”
MIC member Raj Hundal, market policy and practices manager with Powerex, asked Smith to elaborate on the benefit of improved positioning in unit commitment. “Is that not occurring with the [reliability coordinators] right now? Are they not positioning themselves, or are they not seeing something there that’s going to be different?” he asked.
Smith said the role of the RCs is to keep BAAs “between the digits so you can get out of a problem,” not to minimize the system cost impacts of congestion. “They’re just there to ensure that the congestion can be resolved,” whereas an EIM day-ahead process will position the system so that the operator will have to mover fewer units “out of the way” in real time, he said.
“When we say better positioning in the real-time, there is definitely an economic aspect to that,” he said.
Illiquidity Trap
The study points to another likely risk: reduced liquidity in the region’s bilateral day-ahead market. A similar development has already occurred in the real-time bilateral market as more Western BAAs have joined the EIM, compelling others to sign up. (See EIM Entrants Cite Changing West as Motivation for Joining.)
Andrew Meyers, a public utility specialist on the Bonneville Power Administration’s trading floor, said the study assumes that EIM day-ahead market participants will turn over the day-ahead unit commitments to CAISO.
“As a result of that, we believe you’ll see a natural reduction in day-ahead, physical, bilateral activity as entities join the EIM plus [day-ahead],” creating “different pools of liquidity in the day-ahead arena” and leaving non-EIM entities to trade only among themselves.
And while Meyers said it would be “premature” to say what type of resource sufficiency test CAISO will perform to prevent EIM entities from leaning on each other in the day-ahead market, the working group anticipates there will be some sort of sufficiency check.
“We think entities failing resource sufficiency would be seeking supply to become resource sufficient … by going out to that bilateral pool. If that’s only a few folks or a small number, it may be more challenging for folks to be successful for grabbing the energy that they were hoping to locate,” Meyers said.
“As a part of a BA, and somebody without a huge amount of resources ourselves … I think it would be a problem for us, especially in a day-ahead market when we may have limits to the contracts we have now,” said MIC member Mike Shapley, a short-term power trader with Snohomish Public Utility District, which sits within the BPA BAA.
“I believe you have valid concerns,” said working group member Robert Follini, manager of preschedule and real-time trading at Avista. “It’s going to be something you’re going to have to go to your company with and see how you will position yourself.”
Ginocchio said the working group plans to post a draft of the EDAM report to the WECC website in mid-March. The final report should be released in late May.
NERC’s Performance Analysis Subcommittee (PAS) is preparing a data request to expand the Generating Availability Data System (GADS) to cover solar generation facilities, in addition to increasing the range of data that the system collects from wind and conventional generators.
Solar facilities of 20 MW or greater will be asked to provide plant configuration, connected energy storage, performance and event reporting, and equipment outage details under a new GADS-PV system.
Wind facilities of 75 MW or greater, which report under GADS-W, will be asked for size and other configuration data on connected energy storage.
Conventional facilities of at least 20 MW, which report to GADS, will be asked for common attributes for all unit types plus additional unit-specific characteristics. Both wind and conventional generators will also be required to provide event reporting data for the first time. The new requirements for wind and conventional facilities would take effect on July 1, 2021.
Solar plants would be covered under new GADS reporting standards. | Consumers Energy
Presenting the proposal at this week’s PAS meeting, Margaret Pate, reliability risk control program liaison for NERC, said solar facilities would be phased into GADS in order to give generation operators time to adapt their protocols. Voluntary reporting would begin on July 1, 2021, and run through the end of the year. Mandatory reporting for solar facilities of 50 MW or greater would begin on Jan. 1, 2022, and would be extended to facilities of 20 MW or greater the following year.
In response to a question from PAS Chair Maggie Peacock about whether the GADS working group had considered applying the same requirements to all three types of generation, Pate said it had not. “I think the nature of the way that renewable plants are owned and operated is very different from … conventional [plants], from our experience and from what we’ve heard from the industry,” she said.
Reporting Threshold Questioned
Several subcommittee members suggested that the GADS team also consider changing the threshold for reporting generation outages. Under the current proposal, operators of solar facilities would be required to report a loss of capacity of at least 20 MW, lasting 10 minutes or longer — the same requirement that applies to wind. David Penney of Texas Reliability Entity and Joe Eto of the Lawrence Berkeley National Laboratory asked if the threshold could be changed to that required of conventional generators, which are required to report outages of one minute or more.
“My concern was that it’s the short-duration, momentary cessation [events] that have gotten flagged in our State of Reliability Report. … A number of special alerts [have] been issued by NERC around that, and [the Inverter-Based Resource Performance Task Force] is very focused on getting vendors to modify their equipment to prevent that behavior from taking place,” Eto said. “Someone ought to memorialize that we’ve succeeded by measuring when these things happen and that they’re decreasing in frequency and extent.”
Donna Pratt, performance analysis manager for data analytics at NERC, said the threshold was chosen after feedback from industry representatives that meeting the same standard as conventional generators would be “very difficult … because of the nature of the way that wind and solar operate.” The 10-minute time limit would give operators time to address temporary outages that might result from momentary supply disruptions rather than equipment issues.
The GADS working group plans to continue working on its data request after the Planning Committee’s meeting March 3. Depending on when it finishes reviewing the request, the subcommittee will pass it to either the PC or the new Reliability and Security Technical Committee. The PAS hopes to submit the plan for review by NERC’s Board of Trustees at its November meeting.
FERC on Thursday issued a Notice of Inquiry seeking industry comments on the “potential benefits and risks” to the bulk electric system posed by virtualization and cloud computing services (RM20-8). Separately, the commission ordered NERC to provide information on two existing draft critical infrastructure protection (CIP) reliability standards relating to the same topics (RD20-2).
The NOI issued at the commission’s open meeting builds off of discussions at the commission’s annual technical conference on reliability last year, as well as a tech conference on security investments for energy infrastructure in March 2019 sponsored by FERC and the Department of Defense. (See Reliability Conference: Deterrence or Collaboration?)
Industry Input Sought on Cloud Services
FERC is requesting comment from industry players on four topics:
The scope of potential use of virtualization and cloud computing services;
Potential benefits and risks associated with these services;
Obstacles to adopting virtualization and cloud computing posed by existing CIP standards; and
Possible uses of new and emerging technologies in the current CIP standards framework.
Patricia Eke, Office of Electric Reliability
FERC said comments submitted will inform its decision on whether to direct NERC to modify CIP standards to facilitate the use of virtualization and cloud computing by operators, addressing a key shortcoming identified by commissioners in the existing framework.
“The currently effective CIP reliability standards were developed in an era when registered entities would procure, manage and use their own computing systems to facilitate reliable bulk electric system operations,” Patricia Eke, with the Office of Electric Reliability, said in a presentation to the commission at its open meeting. “Thus, the development of the reliability standards did not contemplate explicitly how such computing systems could be deployed in a cloud computing environment.”
Comments are due 60 days after the NOI’s publication in the Federal Register.
NERC to Provide CIP Standard Updates
In conjunction with the NOI, the commission also directed NERC to make an informational filing describing work on Projects 2016-02 and 2019-02, including their current status, interim target dates and anticipated filing dates for new standards. NERC must submit its informational filing within 30 days of the issuance of the order, with quarterly status updates until new standards are filed.
Kevin Ryan, Office of the General Counsel
Project 2016-02 was started in 2016 in response to a directive in FERC Order 822 relating to the protection of transient electronic devices used in low-impact BES cyber systems. Eke said FERC sought more information on it because “the standard authorization request for the project … includes matters beyond Order 822 directives, including industry-requested revisions to support the use of virtualization technologies by registered entities.”
Project 2019-02 launched last year and is intended to improve BES reliability by providing entities with more options for managing their BES cyber system information. FERC required the informational filing because of its mandate to address third-party storage and analysis systems and clarify protections expected when using such solutions.
“It’s pretty clear from the two technical conferences we’ve had on this issue that this is where the industry is heading: towards more cloud computing, more virtualization. And I think it’s just as important from our perspective to make sure this transition is done in a safe and secure and, obviously, reliable manner,” Commissioner Richard Glick said.
WASHINGTON — FERC on Thursday narrowed the resources exempt from NYISO’s buyer-side market power mitigation (BSM) rules in southeastern New York, ordering the ISO to subject storage and demand response to a minimum offer floor in its capacity market.
In doing so, the commission granted a request for rehearing by the Independent Power Producers of New York, partly reversing its 2017 decision to grant a blanket exemption from the rules for special-case resources (SCRs), a type of DR (EL16-92, ER17-996). (See ‘Special Case’ DR Exempted from MOPR in NYISO.) FERC ordered that all new SCRs be subject to the rules. It also decided it will evaluate retail-level DR programs on a program-specific basis to determine whether their payments should be excluded from the calculation of SCRs’ offer floors, initiating a paper hearing to gather information on the programs.
The commission also denied a complaint from the New York Public Service Commission and the New York State Energy Research and Development Authority seeking an exemption for electric storage resources (ESRs), ruling that applying “buyer-side market power mitigation to electric storage resources in NYISO appropriately protects the capacity markets from the price-suppressive effects of resources receiving out-of-market support” (EL19-86).
Nine Mile Point nuclear plant in Oswego, N.Y. | Constellation Energy Nuclear Group
FERC also rejected NYISO’s proposed 1,000-MW cap on the exemption for renewable resources and a proposal to allow state entities to be eligible for the exemption for self-supply resources (ER16-1404). The proposals were part of a compliance filing the ISO filed in response to FERC ordering it to exempt a narrowly defined set of renewable and self-supply resources.
“Rather than basing the megawatt cap on the mitigated capacity zones, NYISO proposes a megawatt cap based on historical entry of all resource types across the entire [New York Control Area],” FERC said. “We reiterate that NYISO must develop a megawatt cap narrowly tailored to the mitigated capacity zones that recognizes that only eligible renewable resources entering the mitigated capacity zones are subject to the buyer-side market power mitigation rules and, therefore, are eligible to apply for the renewable resources exemption.”
Commissioner Richard Glick dissented on the three orders and issued a concurrence on a fourth ruling upholding the commission’s rejection of a complaint by IPPNY seeking to apply the rules to existing capacity resources retained pursuant to a reliability support service agreement and those with repowering agreements (EL13-62).
IPPNY had also requested that NYISO’s BSM rules be applied statewide, which the commission also rejected. Only resources in the G-J Locality, consisting of the Lower Hudson Valley (Zones G, H and I) and New York City (J), are subject to the rules.
In announcing the commission’s decisions at its open meeting, Chairman Neil Chatterjee said they “narrow the scope of exemptions from the BSM rules, thereby broadening the market’s protections against price distortion. … Consumers benefit when our organized markets remain competitive and send the right price signals.”
Chatterjee acknowledged the speculation that the commission would be taking the same action as its expansion of PJM’s minimum offer price rule (MOPR) in December. (See “MOPR Contagion?” PJM Seeks to Quell ‘Inflammatory’ Exit Talks.) “These two markets’ footprints and capacity constructs are very different, and our orders today are shaped by the unique issues that arise in New York ISO and the particular complaints brought by parties in these proceedings,” he said. “However, the underlying principles for both actions are similar: We are working to ensure that capacity markets provide accurate price signals to ensure adequate supply where it’s needed.”
Commenting on his dissents, Glick said, “It’s comical to suggest that what we’re doing here in New York … has anything to do with buyer-side market power. … Most of the resources affected by today’s orders aren’t even buyers. And those that are, very few of them have actual market power. And yet the commission has decided to subject them all to a mitigation regime that’s going to increase prices and make renewables, demand response and energy storage less likely to clear in the market.”
Glick rejected Chatterjee’s “underlying principles,” instead saying that the orders, as well as the PJM MOPR expansion and ISO-NE’s Competitive Auctions with Sponsored Policy Resources construct, mean the commission wants “to raise prices for existing generators and stunt the development of new clean energy resources, which so many states are eager to promote.”
“The fact is we’ve created one big mess in the Eastern capacity markets, and I don’t think my colleagues have a plan for getting us out of it.”
New York’s only coal-fired plant in service, the 686-MW Somerset plant, is set to close as early as March 2020.
Commissioner Bernard McNamee said in response that “our obligation is not to impose a worldview on those different RTOs or ISOs. Instead, it’s to look at, how are they developed? What are the resources that are available to them? How does their load look? … My goal is not to give some overarching theme, but instead to address the issues that are before us.”
Though FERC did not publish the orders until well after the end of the open meeting, clean energy groups were quick to lambast them.
“FERC does not appear to value the contribution of clean energy resources to fight climate change,” the Alliance for Clean Energy New York said. “The FERC decisions create an unnecessary barrier to entry of new renewable energy resources that are essential to achieving New York state’s Climate Leadership and Community Protection Act goals to address climate change.”
“FERC delivered a new subsidy to the fossil fuel industry today at the unfortunate expense of New York ratepayers,” said Gregory Wetstone, CEO of the American Council on Renewable Energy. “This is an echo of FERC’s so-called ‘MOPR’ decision in December that delivered a Christmas gift to fossil fuels in the PJM capacity market. FERC has once again made a decision that will lead to more pollution and higher electricity rates, this time for New Yorkers.”
The Natural Resources Defense Council said the orders are “the latest attempt by a hyper-politicized Trump FERC to try and pose barriers to states deploying clean energy resources.”
“We are encouraged that FERC’s decisions recognize the NYISO’s markets as a strong platform to address the challenges of a grid in transition,” NYISO CEO Rich Dewey said. “The NYISO is working quickly to develop a compliance plan in response to the FERC decisions that will also help New York meet its aggressive clean energy goals. The NYISO is confident carbon pricing in the wholesale markets can also address the federal, state and stakeholder concerns highlighted in these proceedings.”
The New York PSC has initiated a proceeding on whether NYISO’s capacity market is an effective tool to meet the state’s ambitious clean energy and emission-reduction goals. (See NYPSC Opens Resource Adequacy Proceeding.) Speaking to reporters after the meeting, Chatterjee declined to speculate what the PSC would do in response to FERC’s orders or how they would affect NYISO and the state’s joint effort to price carbon into the markets.
“In my view, today’s orders protect the competitiveness of New York ISO’s capacity market by addressing the price-distorting actions that could have unintended impacts on the future supply of electricity for consumers,” he said. “This is a technology-neutral, fuel-neutral approach to trying to protect the competitiveness of the capacity market.”
ERCOT’s Technical Advisory Committee for this month will be conducted via a webinar rather than in-person, given the limited number of items to discuss.
TAC Chair Bob Helton has scheduled the online information session for 9:30 a.m. CT on Wednesday.
Committee members will be briefed on a change to the Resource Registration Glossary (RRGRR021) that adds new data requirements for dynamic models in the Transient Security Assessment Tool. The committee will vote by email on the urgent change request.
Calling it a “leadership transition,” CenterPoint Energy said late Wednesday that Scott Prochazka has stepped down as the utility’s CEO. He will be replaced by John Somerhalder II, a member of CenterPoint’s board of directors, who will serve as interim CEO.
Prochazka’s departure comes less than a week after the Texas Public Utility Commission approved a settlement in a proposed CenterPoint rate case that lowered the Houston utility’s return on equity from 10% to 9.4%. CenterPoint also agreed to a $13 million rate increase, far below its initial $161 million ask. (See PUCT Approves Reduced CenterPoint Rate Request.)
Milton Carroll, the board’s executive chairman, thanked Prochazka for his “meaningful contributions” and for leading the company through “significant growth and transformation.” However, he also said the board had determined that “now is the right time for a new leader with a fresh strategic perspective to lead the company through its next phase of growth and value creation.”
Under Prochazka, CenterPoint acquired Indiana utility Vectren for $6 billion last year. He had been with the utility since 2001, being named CEO in 2013.
Somerhalder II has 40 years of energy experience, including nine and a half years as CEO of natural-gas utility AGL Resources. He has been on CenterPoint’s board since 2016.
CenterPoint announced the shakeup after the market closed Wednesday. Its share price lost almost 3% on Thursday, closing down 71 cents at $25.72. The company has scheduled its year-end earnings call for Feb. 27, where it said it will announce “strong full-year 2019 results and provide 2020 [earnings-per-share] guidance.”
CAISO announced Wednesday that its president and CEO, Steve Berberich, intends to retire by early summer.
“Berberich has been at the helm of California’s power grid and wholesale market operator for nearly a decade, steering the organization during the integration of record amounts of renewable resources and expanding power markets regionally to benefit consumers across the western United States,” the ISO said in a news release.
The CAISO Board of Governors has started searching for a successor, it said.
“It has been an honor and privilege to lead such an extraordinary and talented team of professionals here at the ISO,” Berberich said. “I’m incredibly proud of their work and the successes we have had together in this historic energy sector transformation. I have witnessed this organization perform at the highest of levels, reaching milestones not thought possible before.”
Berberich served 14 years with the ISO, nine of them as CEO. Prior to becoming CEO, Berberich held a series of executive positions at the ISO, including vice president of technology, chief financial officer and chief operating officer.
“He was instrumental in installing industry-leading energy management and market systems, reducing reliance on fossil fuels in the electricity supply, and in welcoming new resources into the ISO’s wholesale markets,” CAISO said. “In 2014, he was recognized as one of the top 10 most influential energy leaders in the nation. Under his leadership, the ISO has been recognized internationally as a leader in renewable resource integration.”
Berberich was a key player in starting the Western Energy Imbalance Market in 2014. The interstate trading market has provided nearly $862 million in benefits to its nine participants and is on a path to expand to every state in the Western Interconnection.
Board Chair Dave Olsen praised Berberich for his service.
“His visionary leadership has put the ISO at the forefront of the worldwide transition to low-carbon electricity,” Olsen said. “His legacy is in an organization now thoughtfully positioned and more determined than ever to push toward that goal.”
The president of the California Public Utilities Commission called late Tuesday for escalating oversight and enforcement actions against Pacific Gas and Electric and said receivership may be necessary if the company can’t provide safe service once it exits bankruptcy.
“The receiver, if appointed by the superior court, would be empowered to control and operate PG&E’s business units in the public interest but not dispose of the operations, assets, business or PG&E stock,” President Marybel Batjer wrote in her proposed ruling.
CPUC President Marybel Batjer | California State Assembly
Batjer is the commissioner assigned to the CPUC’s investigation of PG&E’s bankruptcy proceeding under Assembly Bill 1054, passed last July (I.19-09-016). The commission and the U.S. Bankruptcy Court must approve PG&E’s restructuring plan by June 30 for it to participate in the state wildfire insurance fund created by AB 1054.
The measure requires the CPUC to approve the utility’s reorganization plan including the “electrical corporation’s resulting governance structure as being acceptable in light of the electrical corporation’s safety history, criminal probation, recent financial condition and other factors deemed relevant by the commission.”
Batjer’s 10 proposals focus on operational and financial changes meant to enhance safety. Some were first proposed by PG&E in recent testimony.
To address ongoing concerns, PG&E suggested appointing an independent safety adviser after the tenure of its court-appointed monitor ends, a plan Batjer adopted as part of her proposals. The company has the monitor as part of its probation resulting from the 2010 San Bruno pipeline explosion. Jurors in federal court convicted PG&E in 2016 of six felonies related to that disaster. A series of catastrophic wildfires in recent years led the company to seek bankruptcy protection in January 2019.
In another proposal, Batjer echoed a prior demand by Gov. Gavin Newsom for changes in the leadership of the utility and its holding company. (See PG&E Tries to Appease Governor with New Plan.)
“At least 50% of the directors should be California residents at the time of their election,” Batjer wrote. “There should be the presumption that the reorganized PG&E and PG&E Corp. boards of directors will be comprised of individuals not currently serving on the boards.”
She also proposed tying executive compensation to safety performance.
The largest part of Batjer’s ruling describes a six-step process of correcting potential PG&E failures to comply with state law and regulations. Her outline starts with enhanced reporting by PG&E to the CPUC of its safety performance.
Continuing problems would be met with an escalation of government monitoring and control including enhanced commission oversight, appointment of a third-party monitor, appointment of a chief restructuring officer and finally the installation of a court-appointed receiver.
“If PG&E, or any utility, is perceived as struggling to deliver on its responsibilities to the point that the legislature tasks the CPUC with ensuring that the utility develops a governance structure that responds to its ‘safety history, criminal probation, recent financial condition and other factors,’ then it is the CPUC’s responsibility to identify and develop remedial measures,” Batjer said in her statement.
The CPUC is seeking stakeholder input on the proposals beginning at an evidentiary hearing Feb. 26 and continuing during hearings throughout March.
On Tuesday, PG&E reported multibillion-dollar losses but said it expects sustainable financial performance after it emerges from reorganization. (See related story, PG&E Reports $3.6 Billion Q4 Loss.)
PJM began to sketch out how it will respond to FERC’s order expanding the minimum offer price rule (MOPR) Wednesday, suggesting that it may compress the schedule for the delayed 2022/23 Base Residual Auction and subsequent auctions.
At a special meeting Wednesday morning of the Market Implementation Committee, PJM also said it was considering eliminating two of three Incremental Auctions.
PJM will develop a schedule “that meets everyone’s needs to the best of our abilities,” said Adam Keech, vice president of market services, who added that the schedule will ultimately depend on how quickly FERC rules on the RTO’s compliance with its Dec. 19 order. PJM has said it will not schedule a capacity auction until after FERC rules on its compliance filing due March 18.
Keech said the RTO could compress the normal nine-month schedule into six months by shifting three deadlines that normally occur in months nine through six: nominations for winter capacity interconnection rights (CIRs); submission of seller peak-shaving adjustment plans; and preliminary must-offer exemptions for deactivations.
Typical PJM capacity auction schedule | PJM
Keech said leaving the schedule as is could mean those deadlines would come for a given delivery year before PJM had results of the previous auction.
Greg Carmean, executive director of the Organization of PJM States Inc. (OPSI), said his members need time to evaluate FERC’s compliance ruling to see if they need to make changes in state policy. OPSI sent the Board of Managers a letter last week asking for at least 12 months after FERC’s compliance order before the next BRA but to cap the schedule so the auction is held no later than May 31, 2021.
“That’s crazy,” Tom Hoatson of LS Power said of such a delay. “There’s business decisions, there’s investment decisions currently on hold. … I think you could run an auction as early as this fall for 2022/23.”
Richard Seide of Apex Clean Energy asked how PJM would respond if Maryland pulls out of the capacity market and adopts a fixed resource requirement (FRR).
But Marji Philips of LS Power called it a “gross exaggeration to say the world has changed.”
“I think it’s time we stop talking about a house on fire. It’s not on fire. … At least for the upcoming auction, there isn’t a lot that has changed.”
“All these ‘what ifs’ are not compelling,” said Bob O’Connell of Panda Power Funds. “PJM needs to set a schedule that includes all preliminary activity. We can always find reasons to push it off.”
Implied net avoidable-cost rate (ACR) for nuclear plants including capital expenditures | Monitoring Analytics
Carl Johnson of the PJM Public Power Coalition asked PJM and the Independent Market Monitor whether they expected to have to review more units going through the unit-specific exemption process under the new rules.
“I expect it will be more. How much more, I don’t know,” Keech said, adding that it will depend on the values set for the net cost of new entry (CONE) and avoidable-cost rate (ACR).
“It will be more — probably significantly more,” Monitor Joe Bowring said. But he said the Monitor is trying to streamline its review process. “We don’t want to be the thing that slows us down,” he said. “We’re happy to move as quickly as people need us to.”
Exelon’s Jason Barker said shortening the schedule from nine to six months “seems reasonable” but that it would be disruptive to have overlapping auctions because it could put unit owners in a position of having to make retirement decisions for a subsequent delivery year without knowing if it cleared in a prior delivery year.
“You can put all the caveats in the world around that. It has real-world implications,” he said, noting that a plant could see an exodus of its staff after announcing its retirement, even if it is later rescinded.
Keech said PJM is discussing canceling some first and second Incremental Auctions, noting that the postponed BRA for delivery year 2022/23 will likely be after the September date scheduled for the first IA for that period.
He said the RTO may recommend canceling such IAs any time the BRA is later “because you’ve always got the next [IA] coming up.”
If the RTO were to try to reshuffle the IAs, he said, “the logistics around the auction schedule gets extremely complicated.” Such a change would require FERC approval.
IMM to Estimate Cost Impact
In his own presentation on MOPR floor prices, Bowring presented a template for unit-specific exemption requests and an analysis of net ACR costs for nuclear plants.
Barker challenged Bowring’s estimates, saying they fail to account for the plants’ market and operating risks, which should increase prices by $7/MW-day to $18/MW-day. “Risk should be accounted for. It’s not accounted for in these numbers,” he said.
Other speakers questioned using a 20-year asset life for determining the costs of solar generation, saying it is too short.
“We’re not saying it has to be 20 years; that’s what the order is now,” Bowring said. “We think it serves everyone’s interests to have that clarified.”
Bowring also said the Monitor will be publishing “fairly soon” an analysis that will show that the expanded MOPR will not increase capacity clearing prices — contrary to others’ predictions of large increases. In his dissent on the order, Commissioner Richard Glick offered a “back of the envelope” estimate that capacity costs will increase by $2.4 billion annually. (See FERC Extends PJM MOPR to State Subsidies.)
“We’ll point out why that’s not accurate,” Bowring said of Glick’s estimate. But he said the Monitor will not forecast prices for individual locational deliverability areas because that could reveal confidential information and influence bidding behavior. “We don’t want to get out ahead of the market,” he said.
‘Death Penalty’
Seide challenged PJM for changing its interpretation of what he called the “death penalty” for resources that claim the competitive exemption but later accept a state subsidy.
Paragraph 162 of the order says an existing resource that claims the competitive exemption for a capacity delivery year, but later accepts a state subsidy for any part of that delivery year, will be denied capacity market revenues for any part of that year.
The commission said a new resource that claims the competitive exemption in its first year and later accepts a subsidy “may not participate in the capacity market from that point forward for a period of years equal to the applicable asset life that PJM used to set the default offer floor in the auction that the new asset first cleared.”
“Absent this change, PJM’s proposed language would allow gaming and incent the creation of subsidy programs timed to avoid the qualification window,” the commission said.
MIC Chair Lisa Morelli acknowledged that PJM had considered a narrower interpretation of the ban that would bar new resources for just the delivery year in question. But she said the RTO now agrees with Bowring that FERC intended such a circumstance to result in a lifetime ban.
“If FERC sees that [in PJM’s compliance order] and says that was not what the intent was, then they can correct us,” Morelli said.
“You’re accepting the death penalty,” Seide said.
“We prefer asset life ban,” Morelli responded, prompting laughter.
In their request for rehearing, trade groups representing wind and solar generators said the commission’s proposed rule is “unduly punitive and not proportional to the alleged harm caused.”
Additional MOPR Discussions
In a response to questions from stakeholders, Morelli said PJM won’t publish an “exhaustive list” of what it considers subsidies under the FERC order but will list those on which it agrees with the Monitor in the interest of transparency.
Morelli also released an updated schedule of MOPR discussions, including another special MIC session from 9 a.m. to 12 p.m. on Feb. 28. The MOPR will also be on the agenda for the MIC’s next regular meeting March 11. The Demand Response Subcommittee, which discussed the impact of the expanded MOPR on demand response and energy efficiency Wednesday afternoon, will resume its talks from 9 to 12 on March 12.
