Triple-digit temperatures in parts of Texas last week sent energy demand into record territory and electricity prices soaring to nearly $1,500/MWh.
ERCOT, which manages the energy flow for about 90% of the state’s electric load, set multiple records for May peak demand. The first came May 16, when the ISO topped out at 61.5 GW between 5 and 6 p.m., after having reached 61.1 GW the hour before. It upped that mark to 63.7 GW the next day, a 7.5% increase over the previous record of 59.3 GW set last May.
Demand on May 18 peaked at 63.1 GW during the 4-5 p.m. hour.
ERCOT had predicted a May peak demand of 59.6 GW. Demand peaked at 47.9 GW in April, 9.9% below expectations.
The ISO has projected a summer peak of 72.8 GW in August, which would break the 2016 record of 71.1 GW. It says it has 78.2 GW of capacity available, with a planning reserve margin of 11%. (See ERCOT Gains Additional Capacity to Meet Summer Demand.)
Operating reserves dipped to 3 GW on May 16, just above ERCOT’s emergency level of 2.3 GW, but spokesperson Leslie Sopko said the ISO hasn’t issued any emergency alerts or had any issues with reserves or reliability.
“While load has been high, we have had sufficient generation to meet the demand,” she said. “We expect that will continue through the weekend.”
Average prices jumped to $1,488.86/MWh in the interval ending at 4:45 p.m. on May 16. Prices dropped down below $100/MWh by 6 p.m. and did not crack triple digits the rest of the week.
Temperatures approached 100 degrees Fahrenheit in much of the state Friday. They were forecast to drop into the lower 90s and upper 80s over the weekend, before crawling back up to 100 next weekend.
Small Munis File Appeal with Texas PUC
The Small Public Power Group (SPPG) of Texas, comprising eight small municipally owned utilities with peak loads of 1 to 21 MW, filed an appeal on May 14 with the Public Utility Commission over ERCOT’s definition of transmission owner.
It’s the last resort for the SPPG, which has failed to secure approval through ERCOT’s stakeholder process of a revision request that would exempt municipal distribution service providers without transmission or generation facilities from having to procure designated transmission owner (DTO) services from a third-party provider if their annual peak load is less than 25 MW. (See “Small Public Power Group’s Appeal Again Meets Defeat,” ERCOT Board of Directors Briefs: April 10, 2018.)
The PUC has opened a docket in the proceeding (No. 48366) and directed the group, ERCOT, commission staff and market participants to attempt to reach an agreement. The SPPG must file a report on the discussions by July 9.
The group said none of its members have ever been included in the ERCOT load-shed table, and that their load is “so miniscule that it would not materially change anyone else’s load relief share.” Clark Hill Strasburger’s Tom Anson, who represents the SPPG, wrote in the appeal that several members are physically limited in their ability to comply with relevant ERCOT requirements and that the proposed revision “will not, in any way, affect ERCOT’s system reliability.”
“The commission should recognize that ERCOT’s rules do not fit all circumstances, that there is no reliability issue at stake in this special circumstance and that it is appropriate to modify ERCOT’s rules in this special instance,” Anson said.
The proposed change was developed in 2015 to settle the noncompliant status of municipally owned utilities as PUC staff began to look into the issue.
REDONDO BEACH, Calif. — California’s grid reliability will be increasingly at risk if the state doesn’t soon address its unfocused approach to resource adequacy planning, industry experts said last week.
Panelists at Infocast’s California Energy Summit criticized the policy drift leading to an increasing reliance on reliability-must-run contracts for gas-fired units. They called for a more focused effort to address RA needs as the state brings on a growing volume of renewable resources.
The consensus among the panelists: that RA has become extremely complicated, and commenters during the conference several times touched on a recent “greenbook” report issued by the California Public Utilities Commission that warns that the state’s fragmented decision-making around capacity risks a return to the conditions preceding the Western energy crisis of 2000/01. (See CPUC Cautions of Return to Bad Old Days.)
Jan Smutny-Jones, CEO of the Independent Energy Producers Association, was blunt in his assessment of the situation, saying he has “some very real concerns about the direction the state is currently headed.”
“My job today it to bring you tales of fear and loathing,” he said. “I think that we are short of the RA market for a really long time.” He added that “I don’t think Calpine is responsible for this RA problem,” and that the RMRs are a consequence of the state failing to adequately deal with RA.
“This is insurance. This is very boring except when it isn’t, and when it isn’t, we run into big problems,” Smutny-Jones said. He cautioned that while the momentum for decarbonizing the California grid is not going to abate, it must not compromise reliability and affordability.
Last November, CAISO said California’s investor-owned utilities were about 2,000 MW short of local RA requirements for 2018. The ISO joined with utilities in asking the CPUC to reform the RA program because the state’s resource fleet is quickly shifting to more renewables, which create a need for RMRs. The ISO acknowledged that the situation is not the fault of companies threatening the retirement of gas-fired units, but rather the result of deficiencies in the RA program. (See California Utilities Short on Local RA Capacity.)
“We are sort of the poster child for the failure of the resource adequacy program,” Calpine Director of Market and Regulatory Analysis Matt Barmack said during a panel Wednesday, describing his company’s efforts to secure financial support for struggling generating units. The company has about 5,500 MW of gas-fired and other resources, such as the Big Geysers geothermal plant in California.
Calpine’s Yuba City, Feather River and Metcalf gas plants, totaling about 700 MW, are contracted under CAISO’s RMR program, which provides out-of-market payments to gas units that don’t make adequate revenue to stay in operation but are needed to provide reliability. (See FERC Approves CAISO-Calpine RMR Settlements.)
Barmack said Calpine saw the RMRs “as the only vehicle to get the certainty of compensation we needed just to get the maintenance on these three units that was required.” The current timeline of the state’s RA program finishes late in the year and doesn’t provide forward certainty for suppliers, he added.
James Caldwell, an adviser to the Center for Energy Efficiency and Renewable Technologies said that California’s current focus is on meeting greenhouse gas goals by a certain year but that urgent RA procurement problems should be addressed. The center is a partnership between environmental groups and renewable energy producers that advocates for the growth of renewables in California and the West.
“Let’s get on with it; let’s do what we know we need to do, and do it now,” Caldwell said. If there are significant reliability problems or blackouts, “everybody in this room will probably lose their job.
“The main thing we have to do is have a sense of urgency,” he said, and not wait until there are reliability problems. Gas plants will be needed for a while, but decarbonization of the electricity grid is incompatible with attaining reliability services from fossil fuel plants, he said.
“What it requires are some changes in thinking,” he said, including revising tariff structures, contracting and planning assumptions, rather than a focus on generation technologies. More optionality is needed in RA planning and finding a way to eventually attain reliability without gas plants, he said.
Martin Wyspianski, Pacific Gas and Electric’s senior director of renewable energy, told the forum that the key issue with RA is recognizing that the market is changing. California has brought on a great deal of renewables very quickly, he said, referring to the infamous “duck curve,” which illustrates the impact of solar growth on the state’s ramping needs.
“What CAISO was saying a few years ago was 20 years out is actually happening today,” Wyspianski said, noting that peak demand has shifted from late afternoon to evening as the transition to more renewables occurs, resulting in high pricing at certain periods.
“We are starting to see some of the effects of that shift,” which could signal a worsening situation down the road, he said.
MEXICO CITY — The Gulf Coast Power Association’s third conference on the nascent Mexican market drew almost 100 attendees to participate in discussions on market design, retail tariffs, transmission siting and generation financing. The May 16 event was interrupted for about 15 minutes by a seismic alert that required an evacuation, but conference organizers were able to keep the event on schedule.
Little more than a year ago, Jeff Pavlovic, managing director of the Bravos Energia generation consulting firm, was managing director of electric industry coordination for the Ministry of Energy (SENER), responsible for standing up the Mexican market. Now, as a member of the private sector, he delivered a painfully honest view of the market.
“When you’re not representing the government, you don’t have to sugar-coat things,” he said.
Pavlovic pointed to a lack of transparency in the market and the continued influence of the country’s incumbent monopoly, the Federal Electricity Commission (CFE).
“For a market to work, decisions need to be made by the market participants,” he said. “Decisions should be pushed out to people who have money on the line. And for that to happen, there needs to be transparency for people who have real investments at risk and money in the market.”
Case in point: Last November, Mexico’s Energy Regulatory Commission (CRE) published the market’s first basic retail rates.
But then users in Baja California, which is isolated from much of the Mexican mainland, complained to CRE about errors in their higher rates. That led to a change in the key criteria for rates in February that affected all users, he said.
CRE “changed the way [it] assigned load demand among different users and rate classes. This led to big drops, 30 to 40% drops, across all rate classes,” he said. “It no longer made any sense. It was completely impossible to reproduce. The CRE spreadsheets that were meant to show the math started 80% through the calculations.”
Pavlovic said the original methodology was fundamentally sound and that he hoped CRE would fix the calculations. He said the commission gave up last month and published a new, transitory methodology that appears to phase in rate increases over the rest of 2018.
CRE “seems to be on a trajectory to keep raising rates,” he said. “But the level of transparency and logic is even less than before.”
Pavlovic said distribution losses, or theft — a serious problem in Mexico — are a looming problem in the rates structure. Costs are currently assigned to paying consumers at the lower voltage levels where the losses occur. To compensate, the rates include a mechanism for the cheapest generation to be assigned to the smallest users.
In addition, he said, CFE continues to combine the accounting for its various subsidiaries, which have yet to be unbundled.
“It continues to lose money as a whole, but we can’t tell where they’re losing money because they haven’t separated their results by companies,” Pavlovic said. “They’re starting to make a lot of money from fuel sales and ‘other income,’ which we have no idea what it is.
“CFE is required to publish contracts for energy and fuel,” he said. “That would solve problems where market participants suspect there are deals between CFE companies at either too low or too high a price compared to market conditions, but CFE has resisted this. This is an opportunity for SENER to step in and enforce the transparency requirements established in the law.”
On the bright side, Pavlovic said the market’s capacity auctions have been successful and market participation continues to grow.
“There is a new wave that will come in,” he said. “I think the market will continue to get deeper and help us exercise influence over the policy. But we need CFE to show leadership in its own separation of its businesses.”
Ammper Energia CEO Juan Guichard said he has a “more optimistic view” of the market than Pavlovic, reminding attendees that it was only written into the Mexican Constitution in 2014.
“We’re starting to see a light on the road. Hopefully, it’s not a train,” said Guichard, whose company represents generators. “That’s a market reality … the prices for the new rate and tariff, are not all complete. This is part of the evolution in the market. … We need to reach a middle point between supplier and end customer. We are not used to having choices, so suddenly there is a market, a complicated market with power. There are risks.”
Guichard said the market’s low liquidity limits hedging opportunities, which presents a challenge when meeting customers’ demands.
“Some users have said there’s less liquidity for the operator to cover peak hours or just at night. We need to provide a new solution to customers. We have agreed with the customers, because they’re the first customers going in to a new market,” he said.
Patricio Gamboa, energy director for steel manufacturer Deacero, shared Guichard’s optimism, but noted that the country’s July 1 national election could slow progress. Leftist populist Andres Manuel Lopez Obrador, a two-time mayor of Mexico City, currently has an 18-point lead over the National Action Party’s Ricardo Anaya and a 27-point lead over the Industrial Revolutionary Party’s Jose Antonio Meade of PRI, whose two parties have ruled Mexico for the past 89 years.
“The election year is a lost year, so we have a lot of years to go,” Gamboa said. “When we started this market, we compared it to others. It took them 10 years [to run efficiently], and we are at four years.
“If we compare to other markets, we realize there are many areas of opportunity as far as transparency,” he said. “If the concern is collusion, I agree that to not be transparent is a very high risk. The level of information we have from CENACE is less than other markets.”
A panel focused on regulated transmission rates warned that the transitory rate scheme for 2018 is not helping matters and said changes must be made. Gerardo Cervantes, director of energy marketing for Enel Mexico, said the rate design is inconsistent with the market’s public policies and doesn’t send accurate price signals.
“They designed a market that claims the policy of public power is the recovery of cost. The basic supplier is not recovering costs and is doing poorly,” he said. “When you start implementing [rates] in such a random way, when you put in caps, that means your rate doesn’t have anything to do with what’s happening in the market.”
“We don’t even know clearly which is public policy,” agreed Antonio Noyola, chief development officer for Houston-based energy consultant Avant Energy. “The market is to provide a competitive market, but the design of these supply rates is not real. Reform … is not happening at the right pace. It should happen right away, so they can make the right decision. We need to acknowledge that at the end of the day, [the supplier is] taking a risk.”
“We have to work on providing information to the authorities, so that next January, it’s not challenging,” Cervantes said. “It’s necessary to know the cost of everything, the transmission, the distribution. We need to raise awareness of … the transparency of regulation. If we don’t do it now, or because we are being subsidized, eventually we will have to pay the price — and it’s going to be a very high price.”
Keynote speaker Severo Lopez Mestre Arana, a partner with Galo Energy Consulting, suggested the Mexican market will benefit from continued interaction with other markets. Mexico has five DC ties with the U.S. — three across the Texas border with ERCOT and two with CAISO — with a total capacity of 1,086 MW. Another eight interconnections provide an additional 788 MW of capacity of emergency power.
“We believe with minimal adjustments to regulation, we can move forward,” Mestre said. “You cannot stop the strengths that are pushing to integrate the markets. The strengths are so strong, the power of efficiency and the power of sustainability. The regulation needs to adjust to the reality.”
He said Mexico is interested in extending its interconnections with the U.S., although it has not yet expressed its official intentions. Three additional interconnections between the two countries are in various stages of development. (See Regulators Fear Cross-Border Tx Risks ERCOT’s FERC Exemption.)
| Mexico Ministry of Energy
The key, Mestre said, is completing Mexico’s proposed financial transmission rights market. He used CAISO, ERCOT, PJM and international exchanges such as the EU’s Joint Allocation Office, Inelfe (a DC link between Spain and France) and Energinet DK (Denmark with Germany) as examples of markets with successful exchange capabilities.
“We found that in many markets, that’s a constant that allows for transporting long-term energy or transmission rights,” he said. “We need to extend our assumptions. It seems only minimal changes can lead to a more dynamic model of export exchanges. The model is not that far away. That’s the trend, in most markets.”
Do Low Prices Equate to Successful Auction Prices?
Que Advisors Managing Director Peter Nance, moderating a panel discussion on the market’s recent long- and medium-term auctions, noted the long-term energy auction’s prices were very low at slightly more than $15/MWh. He asked, “Does this mean the process is work well?”
“The cost for the system should also be one of the [measures] of how successful the process is,” said Casiopea Ramirez, regulatory affairs chief for Spain’s Gas Natural Fenosa. “We are increasing the system capacity, but this could also trigger a different process, if we continue introducing capacity with a grid that has not been extended. Demand is low. Logic would say we don’t need additional capacity.”
Ramirez reminded her audience that one of market reform’s goals “is to obtain cheap energy, and we have attained that.”
Veronica Irastorza, an associate director in NERA’s Mexico office, cautiously agreed.
“These low prices are due to natural resources, but also, high risks are assumed in the long-term auctions. All these risks are being assumed by the supplier,” she said. “I’d prefer to see bilateral contracts and CFE to start shrinking over time. You need to have more transparency.
“I do think the auction is really complex and different from other auctions around the world.”
Room for Both Commercial, Development Banks in Mexico
During a panel discussion on financing new generation capacity, Acciona Energia CEO Miguel Angel Alonso recalled his arrival in Mexico in 2006 and the global financial crash two years later.
“I came from Europe, where private banking was covering all the renewable development, but then there was a crisis,” he said, referring to the Lehman Brothers collapse. “It was like watching a love story, and you go … and get some popcorn, and then [return to find] everybody’s dead. The butler killed everybody.
“This is a market that is hard to finance,” Alonso said. “I don’t really see how you can be offering energy at $17. They don’t want to finance. They don’t need it. The ones on top take the cherry. They go with the commercial bank, and there’s no room for the development bank.”
Nacional Financiera’s Arturo Gochicoa Acosta has shown there is still room for development banks. He has helped the government institution finance energy projects with an installed capacity of more than 3.5 GW since 2013.
“We’re not trying to finance projects all around Mexico. We’re definitely doing our analysis,” Gochicoa said. “There’s always the risk of how the energy portfolio changes over the years. What will the infrastructure look like in the next 20 years? You have to look at good projects that are possible and that are able to repay in the long term.”
FERC last week affirmed an administrative law judge’s 2017 decision that SPP’s proposed Tariff revisions to incorporate Tri-State Generation and Transmission Cooperative as a new transmission owner in an existing pricing zone are just and reasonable (ER16-204).
Nebraska Public Power District, the dominant TO in the affected zone, objected to SPP’s decision to incorporate certain Tri-State transmission facilities and the annual transmission revenue requirement (ATRR) into its zone.
Tri-State’s service territory | Tri-State G&T
The commission denied NPPD’s request to reopen the record, saying it failed to demonstrate the existence of “extraordinary circumstances” and that a change in circumstances was “more than just material.”
“NPPD’s motion relies on a change in the criteria that SPP applies to determine zonal placements and additional information” regarding another potential SPP member (Western Area Power Administration-Rocky Mountain Region) joining the RTO, the commission said. “Neither of these arguments demonstrate extraordinary circumstances or changes that go to the heart of the case.”
When SPP adds a new TO to an existing zone, the TO’s ATRR and any of its load not already included in the zonal load are added to the existing zone’s totals, resulting in a new total zonal ATRR and a new total load. That leads to new service rates for all transmission customers within the zone.
NPPD argued that the proposed ATRR, including the proposed return on equity, was not just and reasonable. It said that because Tri-State’s average per-megawatt cost of serving load was higher than NPPD’s average cost of serving its existing load, adding Tri-State would shift more than half of the costs of the co-op’s transmission facilities to existing Zone 17 customers and increase the costs to serve them.
The commission accepted SPP’s Tariff revisions in December 2015, and established hearing and settlement judge procedures over whether the placement of Tri-State’s facilities and ATRR in NPPD’s zone was just and reasonable and whether Tri-State owed any refunds.
ALJ John P. Dring found SPP’s proposed Tariff revisions and their placement of Tri-State’s transmission facilities in NPPD’s zone just and reasonable. He also determined Tri-State owed no refunds in connection with its proposed zonal placement.
FERC agreed that the criteria SPP applied to determine whether Tri-State should be placed in NPPD’s zone “are appropriate for determining zonal placement” in this proceeding. It also sided with Dring that “what matters in this proceeding is whether the criteria render just and reasonable results,” agreeing that SPP’s criteria did so.
“We agree … that shifting cost responsibility for some degree of legacy costs is not per se unjust and reasonable, but there may be cases in which a cost shift would be unjust and unreasonable,” the commission wrote.
Fifteen SPP members joined NPPD in intervening in the docket, many of whom filed a Section 206 complaint in October alleging that SPP’s zonal placement is unjust and unreasonable (EL18-20). FERC rejected the complaint in March, but the TOs have filed a rehearing request. (See FERC Rejects TO Complaint on SPP Zonal Placements.)
Colorado-based Tri-State, a nonprofit cooperative that sells wholesale electricity to its member-owner distribution cooperatives and public power districts in Nebraska, New Mexico and Wyoming, joined SPP in January 2016.
Commission Denies Rehearing Requests on SPP’s ARR, TCR Rules
The commission denied Xcel Energy’s rehearing request of a 2017 order that rejected proposed revisions to SPP’s tariff regarding the eligibility of customers with network service subject to redispatch to receive certain financial transmission rights (ER17-1575).
The commission’s October 2017 order directed SPP to rewrite its rules on auction revenue rights and long-term congestion rights (LTCRs), saying the RTO’s proposed grandfathering provisions would “inappropriately extend practices that the commission finds unjust and unreasonable.” (See FERC Again Rejects SPP Rules on ARRs, LTCRs.)
FERC affirmed its decision to grandfather ARRs and LTCRs that have already been granted to network customers with service subject to redispatch. It had also said it was not reasonable to extend the grandfathering provisions through July 15, 2017, as SPP had proposed as a transition to new ARR/LTCR eligibility rules.
Xcel argued for a rehearing on behalf of its Southwestern Public Service subsidiary, alleging that FERC’s order disregarded SPS’ contractual rights, concluded that network service subject to redispatch is not similarly situated to network service not subject to redispatch and determined that the remedy did not have retroactive effect.
The commission responded that Xcel failed to show that SPP’s Tariff “provided [SPS] with a contractual right that was abrogated” in its Tariff order. FERC found it was reasonable to distinguish “between rights that customers already had been granted and rights that customers may have expected to be allocated.”
“Southwestern is not losing any rights that already have been granted and remains eligible to be allocated ARRs in the future” subject to the limitation in the Tariff order, the commission said.
FERC issued a related order that also addressed Xcel’s claims that the commission had “fundamentally mischaracterized the nature of redispatch service,” rejecting Enel Green Power North America and Southern Company Services’ rehearing request (EL16-110).
Both companies appealed October orders filed along with ER17-1575 (EL16-110 and EL17-69) that found SPP was not barred by its Tariff from allocating ARRs and LTCRs to network customers subject to redispatch for the amounts and periods subject to redispatch during the 2017-2018 annual allocation process. Enel and Southern filed on behalf of their Buffalo Dunes Wind Project and Alabama Power subsidiaries, respectively.
The commission said both parties failed to show that the Oct. 19, 2017, effective date set in EL16-110 for the Tariff revisions is not appropriate. It said the effective date preserved its ability to order refunds, if appropriate, “back to this date.”
FERC said that its decision that SPP’s Tariff revisions do not apply to the 2017-18 annual allocation process “was neither ‘internally inconsistent’ nor erroneous.” It pointed out that the annual ARR and LTCR allocations for 2017/18 were made in March and April 2017, prior to the Tariff revisions’ effective date.
OMPA Complaint Against OG&E Goes to Settlement
The commission set the Oklahoma Municipal Power Authority’s complaint against Oklahoma Gas and Electric for hearing and settlement judge procedures, with a refund effective date of Jan. 26, 2018 (EL18-58).
| Oklahoma Municipal Power Authority
FERC found OMPA raised “issues of material fact that cannot be resolved based upon the record before us.” The state agency filed the complaint in January, alleging that OG&E’s ROE is unjust and unreasonable and that its formula rate needs to be revised to reflect the Tax Cuts and Jobs Act.
The commissioners said OMPA’s analysis was enough to show OG&E’s cost of equity may have declined significantly below its existing 10.6% base ROE. They also said any tax-related changes to OG&E’s formula rate should ensure that its rates properly reflect the effects of the tax legislation.
OG&E said its formula rate will automatically reflect the change in the federal corporate income tax rate, but it will not automatically address the effect of the legislation on accumulated deferred income tax balances.
NATIONAL HARBOR, Md. — Consumer, small-business and environmental advocates pressed PJM’s Board of Managers on the issue of transparency at their annual meeting last week, calling on the RTO to provide more explanation of its broader plans and goals.
Advocates from several member states took turns outlining their shared perspective on what they see as the largest issues PJM is currently addressing and the obstacles the RTO faces.
Brian Lipman with the New Jersey Division of Rate Counsel set the tone during his discussion of PJM’s initiative to reform how energy prices are formed.
“Advocates are supportive of looking at proposals to improve the PJM market, but it needs to be done in the most efficient and effective manner,” he said. “So with energy price formation, one of our first questions is: What happened to LMP?”
He endorsed PJM’s current focus on revising how reserves and shortage pricing are calculated, but added that “it’s unclear to us” whether reviewing the LMP calculation will be a “next step.”
“We’re asking for clear communication on this front,” he said. “There’s much being juggled by all the stakeholders in PJM, and many problems on the table for consideration. … Each one impacts another, so it’s not possible for the consumer advocates or any stakeholder to merely take a look at one piece of the puzzle without thinking about how everything will fit together and what the complete picture is. … We need to know how PJM plans to fit energy price formation into its resilience initiative.”
John R. Evans, Pennsylvania’s small business advocate, said he stays involved because “many times, if you don’t have a seat at the table, you often find yourself on the menu.”
Evans is concerned about the potential for his state legislature to subsidize its nuclear fleet, as has happened in Illinois and New York and is on the brink of approval in New Jersey.
“Show us some benefit to small business classholders,” he said. “So far, we haven’t seen that.”
Erik Heinle of the D.C. Office of the People’s Counsel discussed advocates’ support for increasing PJM’s consideration of cost-containment guarantees in staff’s analysis of transmission construction bids. Stakeholders will consider several different proposals on the topic at a May 24 Markets and Reliability Committee meeting. Heinle’s office joined LS Power in developing a proposal that would require PJM to seek input from the Independent Market Monitor in comparing cost caps to cost estimates. PJM has developed two other proposals: one would limit cost-containment evaluation to construction costs while the other would give RTO staff authority to consider a wider range of factors at its discretion and require them to perform a feasibility evaluation on any cost commitments.
While Heinle advocated for his proposal, he acknowledged the “thorny issue” of having evaluation criteria developed by one stakeholder sector and called PJM’s proposals “a considerable upgrade form the status quo.”
He also addressed supplemental and end-of-life transmission projects, arguing that “the current process does not provide adequate transparency related to data and criteria thresholds each transmission owner uses to prioritize assets for replacement.”
Jackie Roberts, director of the West Virginia Consumer Advocate Division, questioned PJM’s filing in FERC’s resilience docket, saying it made her “uncomfortable” that the comments should have “demonstrated how reliable and resilient our system already is.”
“I don’t think clearing prices are any more artificially low now than they were artificially high several years ago,” she said.
The comments “befuddled” her until she realized they reminded her of how the Obama administration’s Clean Power Plan was developed, she said. It became clear, she said, that such proposals are developed by “someone who doesn’t have the authority to require a market solution.”
“PJM asking for more authority about the gas industry … I don’t understand that,” she said. “I do think there needs to be a gas industry ISO, but PJM is not the entity to do that. That needs to be a parallel, standalone effort.
“I really am not a fan of PJM saying anything that suggests to the public … that we are not resilient and that our fuel mix may not be resilient.”
PJM Response
PJM CEO Andy Ott said legislators have been asking him at what point the grid would become too dependent on one set of infrastructure.
“We have been very clear in our statements about the current situation, even with the current announced retirements, [that] we don’t have a fuel security problem and the system is fine,” he said. “However, 10 years from now, if we continue to see changes in the fuel mix, we have no criteria to look at fuel dependencies and fuel security. … It’s a legitimate question for us to analyze. If you’re insinuating that PJM’s activities here are trying to change certain resources from retirement … I think that’s a misguided suggestion.”
Ott and board members agreed on the importance of prioritizing issues based on significance but defended some of staff’s decisions to move quickly on topics that some stakeholders have questioned.
“In some cases, ‘do nothing’ might not be an option because of whatever drivers are out there,” Ott said. “Ignoring problems isn’t going to make them get any better.”
Board member Charles Robinson said PJM sometimes moves quickly specifically to be “responsive to a cost concern.”
“Sometimes we move quickly because we are concerned about cost impacts, because we feel the need to correct a perceived deficiency so that we can be responsive to a cost concern,” he said.
“The board does take both cost and benefit into consideration,” board member Susan Riley said.
IMM Support
Robinson also questioned a note from the advocates’ slides indicating their support for the Monitor.
“From my perspective, I feel as though we also care a great bit about getting an independent view, and I believe we take it into account,” he said.
“We think the level of cooperation between PJM and the Market Monitor is at an all-time high, so I’m interested in understanding if that bullet was there just to reaffirm or if there is a perceived issue,” Ott added.
Kristin Munsch of the Illinois Citizens Utility Board clarified that it was meant as support for the Monitor going into contract negotiations next year.
“We wanted to go publicly on record that this was important to us,” she said. “Don’t be surprised when you hear consumer advocates going forward reaffirming, making that point, because we understand the discussions that might be coming to the broader PJM community.”
Bill Fields from the Maryland Office of People’s Counsel said the Market Monitor provides information and analysis in stakeholder meetings that might not otherwise exist.
“We find a lot of value in the Market Monitor continuing to provide that assistance to advocates,” he said.
Roberts brought up another concern about PJM attempting to stop Monitor Joe Bowring from filing complaints at FERC.
“Along with PJM, he is the most knowledgeable person about all matters PJM, and we simply don’t understand why there is a problem with him filing complaints at FERC,” Roberts said. “We think that’s an important [thing] you have stifled.”
The Sierra Club’s Mark Kresowik voiced concerns about what he suggested is a common assumption: that environmentalists seek high energy prices in order to drive efficiency.
“The answer is actually ‘no’ because, in addition to clean electricity being the single most important way that we’re doing to reduce carbon pollution from the economy and ultimately combat climate disruption, clean electricity also has to power the rest of the economy … in order to achieve the levels of carbon pollution reductions that we need,” he said. “In order for clean electricity to play that role, it has to outcompete gas and oil in those sectors, which means it needs to be affordable for all.
“We are increasingly concerned that many of the decisions that are made by PJM, that are in the process of being recommended by PJM, threaten to raise costs, particularly for states and consumers that are actively choosing and preferring clean energy, often without a clear reliability benefit.”
He also expressed interest in a comment made by Robinson that the board requests cost analysis on major decisions sent to FERC, noting that no such analysis was included in PJM’s recent filing to revise its capacity construct. (See PJM Capacity Proposals Widely Panned.)
“That’s a major concern for us,” he said, “and we’re seeing similar things going forward.”
Mike Jacobs with the Union of Concerned Scientists said the current capacity construct excludes some resources on the grid and he urged PJM to consider allowing resources more flexibility to make capacity offers into annual, summer or winter auctions.
“Optimization is something this organization knows how to do … instead of being stuck with old models and old resources,” he said.
NATIONAL HARBOR, Md. — Attendees who didn’t pick up on the theme of PJM’s annual meeting last week weren’t listening. “Resilience” was uttered so many times during the General Session that speakers were sheepishly joking about using the word before launching into their own comments.
What did the audience learn from all of it? That it’s complicated. That it requires coordination across multiple organizational levels, and that there’s no template. It’s also likely very expensive — although so are the consequences of disasters when necessary provisions aren’t in place.
Rob Glenn, director of private sector integration for the Federal Emergency Management Agency, urged stakeholders to develop “a culture of preparedness” and run response exercises routinely. Because emergency responders aren’t always paid professionals, he said, coordination needs to occur all the way to the community level and begin well before an event occurs.
Pat Hoffman, the Department of Energy’s principal deputy assistant secretary for the Office of Electricity Delivery and Energy Reliability, warned of cyberattacks on the industry within the next year from Russian hackers.
“Cybersecurity is one of the most important issues facing this industry today,” she said. “We have a huge bullseye on our back. … At this stage of the game, it’s not if but when, so how do we make sure we can continue to operate after an attack?”
The industry is focusing on improvements in sensing technology to support outage recovery, asset management and machine learning, she said. She said one of the industry’s main strengths is being able to articulate how much damage it has sustained from an event, how secure its network remains, what work needs to be accomplished and the steps necessary to move forward.
Resilience Panel
The meeting included a panel discussion on lessons learned about resilience from recent events. Several of the panelists recounted their experiences helping to rebuild Puerto Rico’s electricity grid following Hurricane Maria last year.
Saul Rojas, a vice president of technical compliance for the New York Power Authority, said one of the main takeaways was how tired people were. He said he “never felt so powerless as a manager” when his agency’s satellite phones failed, preventing him from communicating instructions to his crews. NYPA is following up with its vendors to figure out the cause of the problem.
Rojas said NYPA had to think “outside the playbook” in mobilizing to an island with unexpectedly rugged terrain. “When I went to Puerto Rico, I was expecting flat lands and beaches,” he said.
Because of the mountainous terrain and lack of vegetation management in rural areas, the general rule was it took 30 linemen two weeks to restore power to less than 10 customers, he said. “Does it really make sense for them to be connected to the grid? Perhaps … reimagining the grid” with distributed energy resources makes more sense, he said.
Michael Hyland, American Public Power Association’s senior vice president of engineering services, who coordinated with Rojas throughout his time in Puerto Rico, said mobilization was much different than on the U.S. mainland. In contrast with APPA’s mobilization of 60,000 workers in response to Hurricane Irma in Florida, he said, “I can’t just tell them to start driving down I-95.”
He said many utilities don’t recognize the value of mutual aid agreements until they’ve been hit, but that the work in Puerto Rico has been effective. Utilities in Trinidad and Tobago have now joined APPA, he said.
APPA is also developing a variety of drills to simulate potential regional events, such as earthquakes, hurricanes and mudslides. Game theory is also being incorporated to require dynamic responses. “Think [the video game] ‘Oregon Trail,’” he said. “You may die.”
Don Daigler, Southern California Edison’s director of business resilience, recapped his company’s response to last year’s wildfires, noting that at one point there were five fires within its territory for three weeks. He said much of the state was a “powder keg” because of fuel from unusual amounts of undergrowth combined with the “unprecedented” continuation of the hot, dry, fast Santa Anna winds into December.
The company found issues with incident command, executive engagement, real-time investor relations to mitigate stock-price fluctuations, and ground-level strategies to ensure notification. The company embedded workers with fire and lineman experience to provide useful information to responders.
Caitlin Durkovich, a director at Toffler Associates, the strategic consulting and advisory firm founded by “Future Shock” author Alvin Toffler, said the idea is to think about “critical dependencies” between infrastructure systems, such as electricity and water, and realize there are “no bright lines or boundaries” but rather “concentric circles that move outward.” Organizations must be ready to make major changes, said Durkovich, former assistant secretary of infrastructure protection for the U.S. Department of Homeland Security.
Scott Aaronson, Edison Electric Institute’s vice president for security and preparedness, told attendees to focus on unity of effort, message and investment to develop preparedness for a spectrum of possible events.
Ott Defends Fuel Security Initiative
PJM CEO Andy Ott wrapped up the discussion by defending the fuel security initiative announced last month and imploring stakeholders, “I need your help” to improve resilience. (See PJM Seeks to Have Market Value Fuel Security.)
“I do believe that fuel security is resilience,” he said, responding to criticism that the initiative is an effort to funnel money to ailing coal and nuclear plants. “Sometimes folks have been critical of our policies. Sometimes, it’s like democracy: It’s not perfect, but it’s the best game in town.”
The meeting culminated in an emotional sendoff for Board of Managers Chairman Howard Schneider, who was forced by term limits to retire from the board. He was the last of the original board members from its inception in 1997 and was its first and only nonexecutive chairman, assuming the position when it was developed in 2007. (See related story, Retiring PJM Chair Schneider Reflects on 21 Years at the Helm.)
Several members of PJM leadership reflected on Schneider’s term, including Ott, who said Schneider taught him how to run the RTO “the right way, to run it with inclusiveness, to run it with integrity.”
Gabel Associates’ Mike Borgatti, chair of the Members Committee, noted that Schneider’s “fingerprints are all over PJM.”
Ake Almgren, who was later elected to succeed Schneider as chair, praised Schneider for how he “always made the extra effort to engage all board members … making the aggregate board stronger than its individual members.” (See PJM Board Elects New Chair, Welcomes New Member.)
In his farewell remarks, Schneider praised his fellow board members.
“I can truly say to you that you have a strong board with a hardworking and knowledgeable person in every slot,” he said.
He also extended a final peace offering to the Independent Market Monitor, with which he had clashed in the past, calling it “not technically a part of PJM, yet an integral part of PJM.”
“The [Market Monitor] is a good check and balance and has important ideas to convey,” he said.
He requested that PJM and its stakeholders protect its markets, keep grid reliability as a priority and value input from the board.
“It usually provides sage advice,” he said.
Finally, he said, PJM “has prospered over these 21 years and my wish is may it continue to do so.”
Stakeholder Process Reforms
Borgatti teased the launch in June or July of an effort to consider potential changes to the stakeholder process and urged members to become involved in the discussion.
“I think it’s incredibly important that we lean in on this one,” he said. “Anyone who wants to participate needs to be given an opportunity to weigh in.”
The longstanding disagreement over how Entergy once equalized production costs among its operating companies was at the center of two FERC decisions last week, with the commission upholding opinions from two administrative law judges pertaining to a seven-month period of bandwidth calculations from 2005.
The allocation of production costs from 2005 to 2015 among Entergy’s half-dozen operating companies under its multistate system agreement has been a source of disagreement for a decade. Before 2015, the companies functioned as one system, although each had different operating costs. Under the arrangement, Entergy’s low-cost operating companies made payments to the highest-cost company in the system using a “bandwidth” remedy that ensured no operating company had production costs more than 11% above or below the system average.
Regulators in each state where Entergy operates have regularly challenged the annual bandwidth filings, with the Louisiana Public Service Commission long contending that the company’s bandwidth payment calculation was plagued by inconsistencies. (See FERC Affirms Ruling Favoring Entergy Bandwidth Calculation.)
In the first order issued Thursday, FERC affirmed a presiding ALJ’s 2016 finding that interest on the 2005 bandwidth period should begin to accrue starting on June 1, 2006, instead of on June 1, 2005, the first day of a test period, as the Louisiana Public Service Commission had argued (EL01-88-015).
The commission also sided with the judge that Entergy Louisiana should exclude most of its net operating loss accumulated deferred income tax (ADIT) from the bandwidth calculation because it stems from a $1.8 billion tax deduction associated with above-market value energy purchases from a long-term contract with the Vidalia hydroelectric power station ending in 2031. The Vidalia tax deduction was properly excluded from the bandwidth formula to “avoid shifting tax burdens and benefits” to other Entergy operating companies, FERC said. The Louisiana PSC had argued that Entergy Louisiana’s net operating loss ADIT is not a tax savings and should be included in the bandwidth formula.
Hydroelectric station in Vidalia | Brookfield Renewable Power
FERC also agreed that Entergy did not properly account for three regulatory asset deferrals in the 2005 bandwidth calculation and ordered the company to make corrections by switching the deferrals to bandwidth-eligible accounts. The commission confirmed that Entergy should calculate the impact of those accounting changes and make a new compliance filing within 60 days.
In the second order Thursday, FERC affirmed another ALJ’s ruling that Entergy had already addressed the question of how 2005 bandwidth calculations should be handled. The commission said Entergy can use its 2006 compliance filing on bandwidth calculations, which FERC accepted in 2007 (EL01-88-017).
Entergy had questioned whether it could apply its 2006 filing for the bandwidth formula calculation to the seven-month period of bandwidth calculations in 2005 after the Louisiana PSC argued that the 2006 filing was not the properly filed rate for 2005 and could not accommodate a seven-month remedy, as it was designed for an annual calculation. FERC said the Louisiana PSC’s argument amounted to a “collateral attack” on its prior rulings in the Entergy bandwidth calculations.
However, FERC disagreed with the judge that the bandwidth formula used for 2005 must “contain all amendments that have been made to the formula in subsequent years.”
FERC ruled last week that a Michigan soybean farm operating two small biomass plants is not excused from a requirement to file as a qualifying facility under the Public Utility Regulatory Policies Act, but it reduced the consequences of the farm’s yearslong failure to do so.
The commission on Thursday said Zeeland Farm Services had a responsibility to file for QF status, even though the company claimed it was unaware of its filing obligation for 10 years. The order partially waived the filing requirement so the two facilities could be largely treated as QFs for the time they operated out-of-compliance (EL17-70, et al.).
The farm owns two 1.6-MW landfill gas-fueled facilities located at its soybean processing facility in Zeeland, Mich. Under a FERC rule enacted in 2006, generating facilities larger than 1 MW must file for QF status.
Zeeland Farm Services | Google Maps
One of Zeeland Farm’s biomass facilities began operating in late 2005, with the other following in 2008. The farm had sold the output to Consumers Energy under two, seven-year power purchase agreements.
FERC did not shield Zeeland from Sections 205 and 206 of the Federal Power Act, leaving the farm facing refunds for “the time value of the revenues collected … for the entire period that the rate was collected without commission authorization.” The farm has already filed a report approved by FERC earlier this month establishing that over the course of the PPAs, it lost money on fuel expenses and operations and maintenance costs, which totaled about $7.9 million (QF17-935). Zeeland collected a total $7.6 million for energy and capacity sold to Consumers, and the commission agreed a refund report should not be required because the farm was unable to recover some variable costs.
FERC also said Zeeland will not have to refund the difference between a market-based rate and a cost-justified rate, as the FPA prescribes, because rates were negotiated with Consumers.
Zeeland said it only became aware of the filing requirement in late 2016, and it filed notices of self-certification last May after informing Consumers of the mistake and conducting a review to make sure the biomass plants still fit the QF definition. Zeeland said its failure to timely submit notices of self-certification was the result of a “good-faith, inadvertent error by individuals and companies otherwise not engaged in the power business.”
But the commission didn’t express sympathy for the oversight. “Zeeland Farm has not justified its failure to comply with a filing requirement that has been present in the commission’s regulations since 2006,” FERC said. “In similar situations, the commission has not been persuaded by claims that the facility met all other requirements for QF status because that argument improperly minimizes the importance of the filing requirement.”
FERC on Thursday rejected the Edison Electric Institute’s request for rehearing of its 2016 order on handling of Critical Energy Infrastructure Information but offered clarification on several points.
EEI challenged several aspects of Order 833, which implemented the CEII provisions attached to the 2015 Fixing America’s Surface Transportation (FAST) Act. (See FERC OKs Information Security, FOIA Rules.) It said the commission failed to adequately specify the criteria it uses to determine whether a member of the public is eligible to obtain CEII.
The commission responded that it has obtained “vast experience” since instituting the CEII process in 2003, noting it “routinely processes CEII requests from, among others, consultants, academics, landowners and public interest groups.”
However, it clarified that “public safety benefits” are one criterion that it should consider in balancing “the requester’s need for the information against the sensitivity of the information.”
EEI also said the commission should revise its CEII nondisclosure agreement “to mitigate against the risk of a CEII recipient involuntarily sharing CEII with a hostile actor.”
FERC declined to change the minimum requirements for the NDA but said the commission’s CEII coordinator “may consider adding additional provisions to the NDA on a case-by-case basis.”
The commission also rejected EEI’s contention that it erred in not providing a way for entities to comment on the sharing of commission-generated CEII.
“The FAST Act does not require, and EEI identifies no provision in the FAST Act requiring, the commission to provide notice and opportunity for public comment about the prospective release or sharing of commission-generated CEII. Furthermore, the commission is not persuaded that we should establish a requirement for stakeholder input when the commission combines information not filed as CEII with other information and potentially creates CEII,” FERC said.
“We, however, clarify that nothing in the FAST Act or the commission’s CEII regulations prevents the CEII coordinator from exercising discretion in an individual situation to solicit comments from a submitter of CEII or other information when evaluating whether to release a commission-generated CEII document.”
Below is a summary of the issues scheduled to be brought to a vote at Thursday’s PJM Markets and Reliability Committee meeting, which will be held at the PJM Conference and Training Center and not its normal location at the Chase Center in Wilmington, Del. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Valley Forge, Pa., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:45)
Members will be asked to endorse the following proposed manual changes:
A. Manual 36: System Restoration. Revisions developed as part of the manual’s annual review; includes clarifications regarding synchro-check relays, blocking governors and black start generators.
B. Manual 3: Transmission Operations. Biannual review to update operating procedures. Revisions update remedial action schemes, sectionalizing schemes and definitions for the Cleveland and Eastern interfaces; designates voltage limits for Ohio Valley Electric Corp.’s impending integration; adds language regarding reactive reserve check submittals and clarifies notes on load shed activity.
C. Manual 11: Energy & Ancillary Services Market Operations. Revisions developed to ensure consistency between the manual and Operating Agreement regarding price-based offers of more than $1,000/MWh. The change was necessitated by FERC Order 831, which required RTOs and ISOs to raise their hard caps for verified cost-based incremental energy offers to $2,000/MWh. (See “Offer Cap Resolution,” PJM Market Implementation Committee Briefs: May 2, 2018.) Also includes conforming changes regarding bidding locations for virtual transactions.
D. Manual 14A: New Services Request Process. Annual review. Revisions developed to introduce the Queue Point software for submitting data for feasibility and system impact studies.
E. Manual 7: Protection Standards. Revisions developed by the Relay Subcommittee to add clarity, update terms and add reliability requirements.
Members will be asked to vote on proposals to include consideration of cost-containment commitments in PJM’s analysis of transmission construction bids. This is the continuation of a discussion that was tabled for four months as stakeholders attempted to find consensus. PJM has two proposals it plans to offer, but LS Power’s proposal will be considered first since a vote on it was deferred at the January MRC. (See Cost Containment Proposal Survives; Headed to MRC.)
Members will be asked to vote on proposals to change rules on submitting variable operations and maintenance (VOM) costs for recovery. Two proposals were endorsed at April’s Market Implementation Committee meeting:
The PJM package, which was supported by a 75% vote, would allow only actual maintenance costs directly tied to electric production can be included in a unit’s incremental energy offer.
The default VOM package, which won an 81% endorsement, would allow resources to choose between filing actual costs under the PJM package or a default value no greater than the new build data published by the U.S. Energy Information Administration.
Members will be asked to endorse OA revisions allowing PJM to share member confidential information with the Eastern Interconnect Data Sharing Network (EIDSN) in addition to NERC and other reliability entities. EIDSN was created in 2014 to develop industry tools that NERC has decided it no longer wants to create and maintain.
