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.
Following a close vote Wednesday, MISO’s Advisory Committee will recommend the RTO create a new sector for hard-to-define members.
The 12-9 vote means the Advisory Committee will advise the Board of Directors that a new Affiliate Members sector is needed so environmental groups in the current Environmental and Other Stakeholder Groups sector can have a singular voice.
The AC will suggest that the new sector not be allowed a vote in either it or the Planning Advisory Committee but have one designated seat for AC meetings and be allowed to offer opinions during the committee’s quarterly hot topic discussions.
The Affiliate Members sector would serve as a home for any MISO member that isn’t participating in another sector. Prospective MISO members must declare a sector affiliation before they can join the RTO.
The AC began debating the merits of an 11th stakeholder sector last year when Lignite Energy Council (LEC), a North Dakota coal lobbying group, approached MISO about membership. Not fitting neatly into any of MISO’s existing 10 sectors, it looked like it would be relegated to the “other” in the Environmental/Other sector. Some AC members said it wasn’t fitting that a sector would contain entities with diametrically opposed views. (See Feb. Vote Planned on 11th MISO Sector.)
MISO’s Power Marketers, Transmission-Dependent Utilities, Transmission Developers and — surprisingly — the Environmental/Other sector opposed the move. Instead, they supported an option that would maintain the Environmental sector’s “other” contingent and prescribe a six-month trial including LEC as a new member. The End-Use Customers sector abstained.
Speaking during the AC’s conference call Wednesday, MISO Deputy General Counsel Timothy Caister said he anticipates the board will now want to hold discussions with the committee over its reasoning behind the decision and its vision for the new sector.
“We stand ready to help support any questions the board or the Advisory Committee might have,” Caister said of MISO’s role.
If approved, the move will require MISO to file changes to its Transmission Owners’ Agreement with FERC.
So far, the proposed Affiliate Members sector seems destined for a fossil-fuel focus.
North Dakota Public Service Commissioner Julie Fedorchak said LEC has penned a nonpublic letter to MISO indicating its support to join the proposed sector. Fedorchak also said the group indicated that it has drummed up interest among other entities interested in joining, including coal and iron mining organizations, coal trade organization America’s Power (formerly known as the American Coalition for Clean Coal Electricity) and various chambers of commerce. As a rule, MISO does not confirm what entities approach it about membership, only revealing new members when its board votes on admitting them.
“We look forward to working with the Lignite Energy Council and others as they join MISO,” AC Chair Audrey Penner said.
America’s Power CEO Michelle Bloodworth said an 11th sector would ensure that “everybody with interest and requisite ability has a seat on the table.”
Bloodworth also asked that the AC revisit the no-vote stipulation in the future as the sector gains more members.
“As the energy industry continues to evolve, key players like the Lignite Energy Council, America’s Power and others who are involved in coal-generated electricity need to remain engaged in MISO’s market discussions,” Bloodworth said in a statement urging the board to support the new sector.
Meanwhile, the AC is planning on holding another panel-style discussion featuring industry experts in lieu of its usual hot topic discussion during next month’s MISO Board Week in New Orleans. The panel will focus on how RTOs deal with resource transition and likely feature one executive apiece from NYISO, CAISO and ERCOT.
Pacific Gas and Electric reported multibillion-dollar losses in its quarterly and annual reports Tuesday but said in a separate five-year forecast that it expects sustainable financial performance after it emerges from Chapter 11 reorganization.
“Our focus now is on working with all key stakeholders, including elected officials and state regulators, to position PG&E for emergence as a financially stable company with a renewed and rigorous focus on safe operations and customer service,” CEO Bill Johnson said in a statement.
| PG&E
The company said it would not hold a call with analysts to discuss its Q4 results but included detailed slide presentations in its filings.
In its annual report, PG&E said it lost $7.7 billion ($14.50/share) in 2019, an increase over the $6.9 billion ( $13.25/share) loss recorded in 2018. Fourth-quarter 2019 losses totaled $3.6 billion ($6.84/share), down from $6.9 billion ($13.24/share) the utility said in its quarterly report.
The losses mostly resulted from the 2017 and 2018 wildfires that drove PG&E to seek bankruptcy protection in January 2019. The fourth quarter numbers include a $5 billion pre-tax charge related to its previously announced $13.5 billion settlement with victims of the November 2018 Camp Fire that leveled the town of Paradise, the October 2017 Northern California wine country fires that destroyed part of the city of Santa Rosa and the 2015 Butte fire in the Sierra Nevada foothills.
In its forecast, PG&E said it expects to invest $37 billion to $41 billion in infrastructure improvements during the next five years, resulting in an 8% growth in rate-based revenues. Most of the investments will go to hardening its grid against wildfires. The outlook lists serious risk factors, including future wildfire liabilities, but says PG&E could see nearly $20 billion in annual revenue growth by 2024.
Reducing wildfire risks and focusing on safety will help it avoid future losses, PG&E said. Two-thirds of its revenues come from owning and operating electric, gas and generation infrastructure, the utility said, with the remaining third coming from pass-through costs for procuring commodities.
U.S. Bankruptcy Judge Dennis Montali and the California Public Utilities Commission must approve PG&E’s bankruptcy plan by June 30 for the utility to be able to participate in a $21 billion state fund to insure utilities against future wildfires. The fund and its participation criteria were included in last year’s Assembly Bill 1054.
Access to the insurance fund is regarded as vital to the company’s future because California holds utilities liable for fires ignited by their equipment regardless of negligence.
“Wildfire settlements, regulatory resolutions, the enactment of AB 1054 and [the] establishment of a multi-year investment and rate roadmap resolve uncertainty and provide stability,” the company said. PG&E has secured $59 billion for reorganization, and an additional $27 billion may be raised through future public offerings.
| PG&E
The company assured the financial sector Tuesday that it’s on track to meet the June 30 deadline because it has reached settlement agreements with fire victims, insurance companies and local governments in deals worth $25.5 billion.
“PG&E has made significant progress in our Chapter 11 cases over the past year,” Johnson said. “We have resolved essentially every consequential issue within the bankruptcy court’s jurisdiction, most notably reaching a [$13.5 billion] settlement with wildfire victims.”
However, many fire victims have begun to question the deal because it allocates nearly $4 billion of the $13.5 billion to reimbursing government entities, including the Federal Emergency Management Agency. (See What SpringCould Bring for PG&E.)
Gov. Gavin Newsom, too, has challenged the bankruptcy plan, saying PG&E would have so much debt that it wouldn’t have the tens of billions of dollars needed to harden its grid.
The utility said it is continuing to work with the governor’s office to resolve his concerns, but it acknowledged in its SEC filings Tuesday that its “ability to meet the eligibility and other requirements [of AB 1054] may be adversely impacted by the California governor’s review of the proposed plan.”
MISO has begun developing the software to create a 30-minute reserve product for use in late 2021.
Following FERC approval of the reserves’ Tariff definition late last month, the RTO said it moved the project status from conceptual design to a software build phase that will last less than two years. The project was originally scheduled to remain in the conceptual design phase through the first half of 2020.
MISO hopes to begin discussing the software with stakeholders at Market Subcommittee meetings during the second quarter of this year.
The reserves will be furnished by either online or offline resources capable of being deployed within 30 minutes to meet local, sub-regional and market-wide needs.
MISO regions requiring short term reserves are indicated with red arrows. | MISO
The RTO expects the new market product will reduce revenue sufficiency guarantee (RSG) make-whole payments, lessen out-of-market commitments, make market prices more transparent and provide pricing signals that incentivize a greater number of fast-start resources that can meet voltage and local reliability requirements more cheaply. Using the reserves, MISO estimates net production cost benefits of $5 million annually and a $1.6 million reduction in RSG make-whole payments paid in MISO South. (See “MISO Preps Tariff for Short-term Reserves,” MISO Market Subcommittee Briefs: Oct. 10, 2019.)
FERC approved MISO’s plan for implementing the reserve product on Jan. 31 (ER20–42).
In the order, the commission disagreed with criticisms raised by Entergy and state regulators in MISO South, who said the proposal was vague and was driven chiefly by economics, not reliability. Entergy and MISO South regulators also demanded MISO conduct more analysis to identify which market participants and load pockets would stand to benefit from the reserve product, arguing that MISO South customers could disproportionally foot the bill for the reserves because it will be used to manage flows on the regional dispatch transfer (RDT) limit between MISO Midwest and MISO South.
FERC said MISO’s reliability versus economic impetus was beside the point.
“Whether managing the RDT is a reliability or economic concern is irrelevant since the limit is a binding constraint that needs to be enforced pursuant to MISO’s settlement agreement with SPP,” the commission said.
FERC said MISO’s reserve design “reasonably allocates costs based on load-ratio share in grouped zones where constraints result in the need” for the reserves. MISO doesn’t need to model benefits according to load pocket, the commission said.
“We find that MISO has supported its proposed short-term reserve product as representing an efficient, transparent, market-based solution for managing post-contingency reserve needs,” FERC said.
