FERC will hold a technical conference July 23 on the “technical and market issues” raised by the growth of hybrid generation and storage resources.
FERC said the conference will run from 9 a.m. to 5 p.m. ET and will be held either in person at commission headquarters at 888 First St. NE, Washington, DC 20426 (with a WebEx option available) or solely via teleconference if necessary due to the coronavirus pandemic.
The commission will issue a supplemental notice before the conference with the agenda and a decision on the venue.
More information is available from Kaitlin Johnson (202-502-8542) for technical questions and Sarah McKinley (202-502-8368) for logistical issues.
Commissioners may participate in the conference.
Commissioner Richard Glick called for a technical conference on hybrids at the Energy Storage Association’s annual Policy Forum in February. Among the questions the commission needs to answer, he said, are how the addition of storage to an existing solar or wind project affects its position in interconnection queues and whether it is treated as a dispatchable or intermittent resource. “We need to learn what some of these issues are — what some of the barriers are — for hybrid technologies,” he said. (See Energy Storage: All Grown Up?)
Duke Energy began testing a hybrid ultracapacitor-battery energy storage system (HESS) at its Rankin Substation in Gaston County, N.C. in 2016. The substation is connected to a 1.2-MW solar installation a mile away. | Maxwell Technologies
Hybrids have been an increasing topic of conversation in the RTOs.
PJM’s Markets and Reliability Committee will be asked at its April 30 meeting to approve creation of a new senior task force to clarify how existing rules for intermittent and energy storage resources would apply to inverter-based solar-battery hybrids. The task force will also consider requirements needed to incorporate hybrids into PJM markets. There are more than 10,000 MW of co-located generation and energy storage hybrid resources in the PJM interconnection queue — more than 95% of the capacity is solar-battery hybrids. (See PJM MRC Moves Forward on Storage, Hybrids.)
NYISO began work in January on development of a model for market participation by front-of-the-meter energy storage resources paired with generation. The Hybrid Storage Model project will evaluate whether co-located storage resources can receive a single dispatch schedule. Co-located resources are currently required to be separately metered. (See NYISO Prepares Hybrid Storage Market Participation.)
In MISO, some stakeholders say hybrid resources are a more pressing matter than the RTO’s storage-as-transmission assets (SATA) proposal. (See MISO Undecided on Amending Storage Plan.)
CAISO is continuing a hybrid resources initiative it began last year. Developers in the state have proposed 25,000 MW of projects that pair storage with existing or new generation. (See CAISO’s 2020 Vision Anticipates Big Change.)
The judge overseeing PG&E’s massive bankruptcy said he wouldn’t approve a letter that lawyers for wildfire victims want to send asking the victims to hold off voting on the utility’s Chapter 11 reorganization proposal.
The victims’ lawyers can send the letter independently, but a court endorsement would be inappropriate and would only cause confusion in a balloting process that’s already complex enough, said U.S. Bankruptcy Judge Dennis Montali in a ruling issued late Tuesday afternoon. Parties in bankruptcies are free to solicit support for their point of view.
“A massive undertaking for sending voluminous materials and soliciting votes on the plan is well-underway,” Montali said. “Hundreds, if not thousands, of members of the class have already voted.
“The [Tort Claimants Committee] apparently does not want to upset those votes, but it is beyond doubt that confusion will reign if the court permits the proposed letter to go out, leaving countless fire victims confused even more than they might be now. Are their cast votes valid? Should they ask to withdraw them? And what happens if there is a pause, and voters do not recast their votes in time?”
“The court is satisfied that agreeing to the TCC’s request will cause more harm than good, and court-approval of its proposal is ill-advised and must be rejected,” the judge said.
Lawyers in PG&E’s bankruptcy case argued Tuesday morning about whether the court should approve a letter to more than 70,000 fire victims informing them of potential flaws in the $13.5 billion settlement that PG&E agreed to in December.
Judge Dennis Montali | Commercial Law League of America
The main problem, the fire victims’ attorneys told federal Judge Dennis Montali, is that the $6.75 billion in PG&E stock promised in the deal may be worth far less because of PG&E’s stock volatility, exacerbated by its heavy debt load and the coronavirus pandemic.
Utility stock is supposed to fund half the victims’ $13.5 billion trust, but the dollar amount isn’t guaranteed — only the percentage of PG&E shares allocated, lawyers explained. At the time the deal was reached, it was anticipated that the shares, amounting to a 21% equity stake in the company, would be worth about $6.75 billion.
That may no longer be the case, victims’ attorney Robert Julian told Montali. Another lawyer estimated the shares would be worth only $4.85 billion, he said.
Julian said he didn’t necessarily agree with such a low an estimate. Even so, he said, the case’s official Tort Claimants Committee (TCC), which he represents, no longer could support the settlement plan and wants fire victims to hold off on voting for PG&E’s Chapter 11 reorganization proposal until the stock issue and other matters can be resolved. (See Fire Victims Challenge PG&E Deal as Vote Looms.)
He accused PG&E at one point of planning to postpone funding the trust with stock until the end of the year as a way to cushion current shareholders from the coronavirus impact. Victims were told previously that the trust would fund in August, he said.
In his ruling, Montali said all the issues raised by the TCC were known when he approved PG&E’s disclosure statement three weeks ago and should have been dealt with then. (See PG&E Tries to Put Bankruptcy Plan in Layman’s Terms.)
‘This Silly Letter’
The proposed letter, as it was filed with the court on Monday, would have asked fire victims to hold off voting for PG&E’s Chapter 11 plan until May 1, but plaintiffs’ lawyers backed off that request Tuesday and suggested April 25 as a deadline to try to negotiate the issues while keeping victims informed by mail.
Robert Julian | Baker & Hostetler
“We want the truth to be told to the victims,” Julian said.
Other creditor groups that settled with PG&E, including insurance companies and hedge funds, will receive all-cash payments, Julian noted. “Fire victims are the only ones standing with this risk of not getting paid or not getting what they bargained for,” he said.
PG&E lawyer Stephen Karotkin called “this silly letter he wants to send out” a negotiating tactic by Julian and other victims’ lawyers to see if they can get a better deal than the settlement agreement they reached months ago after lengthy negotiations.
“Enough is enough on this issue” of guaranteeing the value of PG&E’s stock, Karotkin said.
Stephen Karotkin | Weil, Gotshal & Manges
PG&E’s plan was recently outlined in a disclosure statement and sent to tens of thousands of creditors along with ballots for the creditors’ — including fire victims — vote on the plan. At this point, any party is free to try to persuade other creditors to vote yes or no, Karotkin said.
Julian and the other TCC attorneys want the court to approve the letter as a shield against malpractice claims later on, he said. Karotkin didn’t oppose the letter but argued strongly against the court adding it’s “imprimatur” by approving it before it is sent to victims.
“[Mr. Julian’s] a big boy. Let him make a decision whether he wants to send it out,” Karotkin told the judge.
‘A Pot of Gold’
Montali said he would take a day or two to consider the arguments before issuing a written ruling, but he made his decision hours later
With the courthouse closed due to coronavirus, the hearing took place during a teleconference frequently interrupted by technical glitches. Some participants were in New York, others in San Francisco. The judge, apparently calling from home, was disconnected twice.
The bankruptcy hearings, with dozens of participants, have continued by phone during the state’s coronavirus lockdown because of the tight deadline PG&E faces.
PG&E is trying to end its bankruptcy by June 30 to take advantage of a state wildfire insurance fund and to avoid a state takeover. Montali approved an agreement Tuesday between PG&E and California Gov. Gavin Newsom that would allow the state or a third party to purchase the company if it doesn’t complete its reorganization by the end of June. (See PG&E Deal with Gov. Allows for Utility’s Sale.)
May 15 is the designated end for voting on the reorganization plan. The June 30 deadline prevents what would otherwise be an ordinary extension of the bankruptcy proceedings, Montali said. The coronavirus has resulted in courts and government agencies extending many other deadlines, he noted.
Gerald Singleton | Singleton Law Firm
The strict timeline that PG&E is under could be jeopardized by a growing grassroots movement among fire victims to reject PG&E’s offer.
Recently, three members of the 11-member TCC, made of up of fire victims, resigned so they could openly criticize the $13.5 billion settlement proposal as a poor deal. One said the TCC’s lawyers had breached their fiduciary duty to victims by failing to disclose its risks. (See Fire Victims Challenge PG&E Deal as Vote Looms.)
At Tuesday’s hearing, fire victim Will Abrams, a frequent self-represented litigant in the bankruptcy court, supported the TCC’s letter and said some lawyers seemed to be telling victims to vote first and ask questions later.
“They’re pitching this as ‘there’s a pot of gold and all you have to do is vote yes,’” Abrams told the judge.
Abrams was one of thousands who lost their homes in the Northern California wine country fires of October 2017 and the Camp Fire in November 2018. State fire investigators blamed most of the wine country blazes and the Camp Fire, the deadliest in state history, on failed PG&E equipment.
PG&E sought bankruptcy protection in January 2019 after the fires saddled it with an estimated $30 billion or more in liabilities to those who lost family members, homes and businesses.
Its bankruptcy is now estimated to cost close to $60 billion, making it among the largest in U.S. history.
New Jersey is winding down a solar energy program that helped place the state near the top of solar production in the country.
The New Jersey Board of Public Utilities announced Monday it was directing staff to close the state’s Solar Renewable Energy Certificate (SREC) registration program effective April 30.
The Clean Energy Act of 2018 (AB-3723), which Gov. Phil Murphy signed into law in May of that year, set new clean energy standards in New Jersey, including a requirement that the BPU would close the SREC program by June 2021 or when 5.1% of the kWh sold in the state was generated by solar. The board said it expects to reach the 5.1% milestone by the end of April.
The Six Flags Great Adventure amusement park in Jackson, N.J., is mostly powered by a 23.5-megawatt solar project that began operation last summer. | Six Flags
The BPU established the SREC program in 2004 to complement the state’s existing solar rebate program. Since then, state officials said more than 3.25 GW of solar systems have been constructed throughout New Jersey, including more than 118,000 residential solar systems.
“While today marks the end of one chapter, it also marks the beginning of a new chapter that I believe will lead to a very successful solar future while also lowering costs for New Jerseyans,” said BPU President Joseph L. Fiordaliso. “With a record year for solar in 2019, the New Jersey solar industry is strong, and I am confident it will continue to be healthy and profitable while playing a key role in fighting climate change and reaching the governor’s goal of 100% clean energy by 2050.”
The SREC program allowed New Jersey to become one of the leading solar energy producers in the country despite its relatively small land size and available space. According to data provided by the BPU, it’s currently ranked seventh in the nation in installed solar capacity and ninth overall in clean energy jobs, with nearly 9,000 solar industry jobs throughout the state.
The most recent report from New Jersey’s Clean Energy Program shows that 447 MW of solar capacity commenced commercial operations in the state between Jan. 1 and Dec. 31, 2019, bringing the state’s total capacity up to 3,190 MW through the end of the year. The state’s previous record for the highest amount of installed solar capacity within a calendar year was in 2011, when 446.8 MW commenced commercial operations.
Six Flags said its array — 11 MW of solar carports and 12.5 MW on 40 acres of ground-mounted solar panels — makes it New Jersey’s largest net metered solar project. | Six Flags
The BPU is replacing the SREC program in two phases, beginning with the Transition Incentive Program, approved by the board in December. The new program was designed to serve as a bridge between the SREC and a yet-to-be determined successor program by issuing fixed-price, 15-year Transition Renewable Energy Certificates (TRECs) to projects that entered the SREC pipeline after Oct. 29, 2018, but had not reached commercial operation as of April 30.
An order issued March 10 by the BPU set the price at $152 per TREC, which a project earns after generating 1 MWh. By comparison, SRECs traded at a weighted average price of $208.99 in February, according to the BPU. The long-term successor program to SREC is currently under development by BPU staff.
Solar projects currently in the system that have yet to be finalized through the SREC were given a 90-day extension by the board because of permitting and inspection issues caused by the COVID-19 pandemic.
“Having leveraged the generous ratepayer subsidies of the past 20 years, the industry can now survive and thrive at a lower cost to ratepayers,” the BPU wrote in its decision. “The board anticipates that New Jersey’s solar market will continue to be a vital and dynamic one as it transitions to a new incentive mechanism, but it has nonetheless made every effort to ensure that this is so.”
The Solar Energy Industries Association estimates solar investment in the state totals more than $10.1 billion and says prices have fallen 38% over the last five years. The trade group expects growth to slow, however, projecting 1.8 GW over the next five years, 41st in the nation.
Citing the need to “provide registered entities with regulatory certainty” during the COVID-19 pandemic, NERC has requested that FERC delay the implementation of several reliability standards that are scheduled to take effect this year (RM15-4, et al.). The organization asked that FERC consider the request on an expedited time frame and issue its decision as soon as possible.
PRC-027-1 (Coordination of protection systems for performance during faults)
Two other standards that are already effective would see some compliance deadlines pushed back. Under PRC-002-2 (Disturbance monitoring and reporting requirements), which took effect July 1, 2016, entities are required to demonstrate 50% compliance with requirements R2-R4 and R6-R11 by July 1; this would be moved back to Jan. 1, 2021. Also, PRC-025-2 (Generator relay loadability) requires entities to establish compliance with certain measures by July 1; this deadline would also be deferred to Jan. 1, 2021.
NERC said extending these deadlines would be “just, reasonable, not unduly discriminatory … would not adversely impact reliability” and would allow utilities to focus on the response to COVID-19 rather than on time-consuming compliance activities. The organization indicated that implementation delays for additional standards may be warranted depending on the progress of the outbreak and subsequent recovery efforts.
NERC Pursues Active Pandemic Response
The request for delay follows a number of steps by NERC and FERC in response to the pandemic. In March the organizations announced they would use regulatory discretion to relax compliance burdens for utilities related to maintaining personnel certification, performance of required periodic actions, and on-site activities such as audits and certifications. (See FERC, NERC Relax Compliance in Light of COVID-19.)
NERC said last week that the industry has “[taken] aggressive steps” in response to the pandemic, with most utilities either having a written response plan or currently developing one, and a majority pledging to support mutual aid requests from others involved in a pandemic emergency. (See Industry Pandemic Prep Encouraging, NERC Says.) The organization’s own response includes the issuance of a Level 2 alert in March, activation of its Business Continuity Plan and shifting upcoming meetings to conference calls or video conferences.
In addition, GridSecCon, the annual security conference sponsored by the Electricity Information Sharing and Analysis Center scheduled for Oct. 20-23, has been canceled this year.
According to the World Health Organization’s latest situation report, more than 1.2 million coronavirus infections have been confirmed worldwide since the disease was first reported in Wuhan, China. More than 67,000 deaths have been directly attributed to the virus globally.
Former ERCOT staffer Carrie Bivens on Monday will begin her new role as director of the grid operator’s Independent Market Monitor.
Bivens has spent nearly 14 years with ERCOT, most recently as director of wholesale operations. She oversaw the Texas grid operator’s day-ahead market and congestion revenue rights auctions, as well as integration of load resources, distributed generation and emergency response service. As a subject matter expert in ERCOT’s stakeholder process, Bivens has made frequent appearances in recent years before both its Board of Directors and the Texas Public Utility Commission.
Carrie Bivens, ERCOT’s new IMM director | ERCOT
Virginia-based Potomac Economics has provided ERCOT’s market monitoring services since 2005 and was recently awarded another stint by the PUC, which has jurisdictional authority over the grid operator. Potomac also serves as the IMM for ISO-NE, MISO and NYISO.
Potomac interviewed the candidates and made the final selection. The PUC was given an opportunity to approve or reject the hire.
“I’m grateful to the PUC and to Potomac Economics for the trust bestowed upon me in this vital era in ERCOT as major initiatives such as real-time co-optimization of energy and ancillary services get underway,” Bivens told RTO Insider.
As the IMM’s director, Bivens will collaborate with the PUC to detect and prevent market manipulation and identify potential design improvements for the ERCOT wholesale market. She said her initial focus will be ensuring a “timely and comprehensive” State of the Market report for 2019. The report traditionally comes out in May or June.
Steve Reedy, who served as the IMM’s acting director following Garza’s departure, will return to his role as assistant director.
In a statement emailed to RTO Insider, ERCOT said, “Carrie Bivens’ skills as a manager and communicator are only exceeded by her intelligence and wit. The PUC could not have made a better choice, and ERCOT will miss her.”
Before coming to ERCOT, Bivens worked at FERC evaluating market-based rate filings and conducting market power analyses. She is a native Texan and a graduate from her hometown University of Houston.
ISO-NE will file two versions of its Energy Security Improvements market design with FERC later this month after the New England Power Pool Participants Committee on Thursday approved a modified version of the RTO’s plan that seeks to reduce its cost to consumers.
ESI would allow the RTO to procure energy call options for three new day-ahead ancillary service products to improve the region’s energy security, particularly in winter when natural gas shortages can leave generators without fuel. Option awards will be co-optimized with all energy supply offers and demand bids in the day-ahead market.
The PC approved three amendments by the New England States Committee on Electricity (NESCOE) by a 61.7% sector-weighted vote, with unanimous support from the Transmission, Publicly Owned Entity and End User sectors and unanimous opposition from the Generators. ISO-NE’s unamended proposal received only 39.6% support, with support from Generators, Suppliers and Alternative Resources and unanimous opposition from the other sectors.
ISO-NE said that although FERC has found that certain compliance filings are not covered by the “jump ball” provisions of the NEPOOL Participants Agreement, it “has committed nonetheless to include in its April 15 filing the same information it would include were the filing a jump ball.”
The RTO said it will include a description of the NESCOE proposal “in detail sufficient to permit reasonable review by the commission, explain [ISO-NE’s] reasons for not adopting the proposal and provide an explanation as to why [ISO-NE] believes its own proposal is superior to the proposal approved by the Participants Committee.”
The result of more than a year of stakeholder meetings, the ESI proposal was prompted by FERC’s July 2018 finding that ISO-NE’s Tariff is not just and reasonable because the RTO lacks a way to address fuel security concerns that it said could result in reliability violations as soon as 2022. The Tariff currently allows cost-of-service agreements only to respond to local transmission security issues (EL18-182, ER18-1509). (See FERC Denies ISO-NE Mystic Waiver, Orders Tariff Changes.)
NEPOOL’s Transmission, Publicly Owned and End User sectors unanimously backed three NESCOE amendments to ISO-NE’s ESI proposal, and a fourth vote that combined all three amendments, while the Generation sector uniformly opposed all the changes. ISO-NE’s unamended proposal had strong support from Generators, Suppliers and Alternative Resources but was unanimously rejected by the three other sectors. | NEPOOL
FERC last August granted the RTO an extension to file the plan by April 15.
In March, the RTO’s unamended proposal failed in the NEPOOL Markets Committee with 42.4% in support, while a proposal including NESCOE’s amendment to set the value of replacement energy reserves (RER) to zero for non-winter months — essentially eliminating it except for three months — only received 51.77% support. (See NEPOOL Markets Committee Briefs: March 24, 2020.)
Mathematics Exercise
The PC approved three amendments proposed by NESCOE before approving the amended ESI package.
Jeff Bentz, NESCOE director of analysis, proposed the amendments “because the concerns we raised as early as April 2019 and even before haven’t been addressed to our satisfaction, and we believe that puts consumers at great risk, especially during extended cold snaps.
“As we sit here today, the only commitment from ISO-NE is to consider increasing the quantities through a yet-to-be determined addition for load forecast error and to add even more consumer cost through some type of forward market concept that likely will increase costs and not add much additional reliability benefit,” Bentz said. “NESCOE brings forward these three amendments to help bring the cost-versus-benefits inequities closer in balance.”
The first amendment to set the RER value to zero for non-winter months passed with 63.76% in favor, as did the second NESCOE amendment, which was to remove the RTO’s ability to adjust reserve levels to account for load forecast errors.
Massachusetts Assistant Attorney General Christina Belew said her office supported the first amendment “because we don’t think the RER product is required under the [Northeast Power Coordinating Council] Directory 5. We think it has a tenuous link to fuel security, and it is disproportionately expensive.” Directory 5 sets minimum requirements for “the amount, availability, distribution and activation of reserve in addition to those specified in applicable NERC standards.”
[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article amplified their remarks afterward to clarify their presentations.]
“This whole effort was built around the Analysis Group’s assessment of a way to pay for a very minor, 10-day LNG contract, so it was all about 10 days of LNG,” said Brett Kruse of Calpine, who voted against all the amendments but supported the RTO’s proposal. “For the record, none of the folks that voted against in the Markets Committee, nor any of the folks who’ve spoken out against it today, have offered an alternative to secure winter fuel security for New England.
“If you look at this as a mathematics exercise, the numbers don’t add up without the entire ISO New England package, and even then, it’s marginal,” he said. “Second, we’ll make prudent business decisions year over year, and if that means going into a winter where we don’t think we’re going to be able to recoup the costs of an LNG contract we probably won’t buy it.”
NESCOE’s third amendment, to include a $10/MWh adder to the strike price in all hours, passed with 61.27% in favor. NESCOE said it would reduce the cost and risk of the energy call option for providers without materially affecting resources’ incentives under the program.
Down, not Out
Bentz said NESCOE’s objections to the unamended ESI proposal fell into two categories.
“First of all, the ISO’s proposal is an unpredictable, year-round call option approach,” Bentz said. “We think it exceeds the scope of the FERC’s order in 2018, and instead of just addressing winter fuel security, the ISO creates this novel, untested and potentially very expensive program for pricing reserves in the day-ahead market.
“Secondly, ISO-NE’s proposal is going to produce an unjust and unreasonable rate,” Bentz continued. “The ISO’s approach is highly vulnerable to producing uncompetitive outcomes due to the inability to effectively mitigate market power. It procures substantially more reserves than the system needs, and at an excessive cost to customers.
“The ESI design is not good value for the money, and collectively, the six New England states are not in favor of this design as being presented here today,” Bentz said.
ISO-NE COO Vamsi Chadalavada offered the grid operator’s perspective on ESI.
“In our view, we are working to balance energy security concerns, not just for the immediate time frame, but for the longer term, and think a more complete design will accomplish that,” Chadalavada said. “We are mindful and sensitive to consumer costs, and it’s certainly been one of the considerations as we built the risk-responsive design.”
The regional electric power system is evolving fast and the RTO has sometimes been reactive, he said.
“This design positions us better as New Englanders because it allows us to be more proactive in terms of the uncertainties that we face,” Chadalavada said.
OKs Early EIP Sunset
The committee also approved Tariff revisions to sunset the RTO’s interim Inventoried Energy Program (IEP) after capacity commitment period 2023/24, one year earlier than the end date in the current Tariff. The early sunset would be conditioned on FERC’s approval of the ESI proposal for implementation no later than June 1, 2024.
FERC in February rejected a request by ISO-NE and NEPOOL to roll back the sunset date for a Tariff provision that allows the RTO to retain a resource for fuel security reasons. The RTO said it plans to refile the Tariff revision when it files its ESI proposal. (See FERC Rejects ISO-NE Fuel Security Sunset Rollback.)
Other Actions
The PC also approved as part of its consent agenda revisions to Market Rule 1 relating to energy efficiency resources’ capacity supply obligations during scarcity conditions, as proposed by NESCOE and recommended by the MC in March.
The committee also unanimously approved revisions to Market Rule 1 to address FERC’s March 10 order rejecting provisions governing how ISO-NE’s Internal Market Monitor calculates the economic life of resources that want to retire or permanently leave the capacity market. The provisions were intended to correct calculations that ISO-NE said overstated the true economics of some resources and could result in improperly high delist bids. But the commission said the rules’ effective date would upset market participants’ “settled expectations” after the Forward Capacity Auction 13 qualification process for delist bids had begun (ER18-1770-002). (See FERC Reverses Ruling on ISO-NE ‘Economic Life’ Rules.)
The proposal asks FERC to make the changes apply prospectively beginning with FCA 16.
ISO-NE CEO Gordon van Welie said that the RTO activated emergency operation procedures to counter the COVID-19 pandemic on March 12 and that “it’s been really gratifying to see how smoothly the transition went.”
“We have all these contingency plans, emergency plans, and have experimented with half the workforce working from home, but we never had to implement them for real before now,” van Welie told the New England Power Pool Participants Committee on Thursday.
The RTO has more than 95% of its workforce now working remotely, with remote deployment to continue through at least May 4, and is taking special care for the health of crews for the two control centers, ISO-NE COO Vamsi Chadalavada said.
“The industry has really come together in a very refreshing and collaborative way,” he said. “I think folks have closed ranks; there’s a lot of cooperation; and best practices are being shared in near real time. There are extensive communication protocols across the country and internationally.”
Comparison of a few similar days between 2019 and 2020 for midweek in the second half of March. 2020 load curves show as lower and delayed ramp in the morning; overnight loads are lower with closings of 24-hour operations. | ISO-NE
The Electric Power Research Institute has been hosting sessions, and the RTO conducts its own conference calls with generators and every key link in the supply chain to ensure reliability, Chadalavada said.
Chadalavada reported overall March 2020 demand approximately 3 to 5% lower than in prior years, with load curves having changed shape with the pandemic outbreak from the second half of March as the New England states started to require people to stay home.
“The load curves that are now being established mimic snow days when people typically stay home and businesses are either shut down or otherwise operating at not full speed,” he said. “We see that the morning ramp is delayed. What used to be a ramp around 7 a.m. is now extending to 8 a.m. or even 9 a.m.”
Comparison of the unadjusted output of a single load forecast model to the actual New England load in March. Peaks and valleys are similar until around March 15, when the coronavirus began to hit the region. | ISO-NE
The situation presents a challenge to forecasting load, especially now, and the deviation from actual load has in the last few days been “north of 3%, so we’re clearly not meeting our target 1.8% error, but our forecasters are vigilant and staying very close to system conditions,” Chadalavada said.
The RTO is exploring the risk of underestimating loads after the pandemic-induced economic shutdown, he said.
With continued choppiness expected over the next week, “we are trying to train our models, but as you can assume, two weeks of training is almost insufficient for any model to upgrade its performance,” Chadalavada said. “Coming out of it will be an even bigger challenge, so right now I see the algorithmic foundation as the biggest challenge for forecasting load.”
In terms of settlement, the RTO has well established procedures, he said.
“If there are any delays in flow of data, and if we have to make adjustments to it because of any reason, I’m sure we will act quickly and work with all of you to do so,” Chadalavada said.
In his monthly litigation report, NEPOOL Secretary David T. Doot delivered noted FERC’s actions last week to delegate additional authority and issue waivers of some requirements in response to the pandemic. (See related story, FERC Loosens Requirements in Pandemic.)
A publication that covers financial mergers and acquisitions said Friday that NextEra Energy is toying with the idea of acquiring Kansas City utility Evergy.
According to M&A by Reorg, recent activist pressure from Elliott Management, which manages funds that own an economic interest equivalent to approximately 10 million shares of Evergy’s common stock, may make the company more willing to consider a sale.
NextEra has hired Citi to advise on the potential acquisition, and internal evaluations are at the preliminary stages, according to the report.
The publication said American Electric Power and Ameren are also said to be interested in Evergy.
NextEra declined to comment, following its policy to not respond to market rumors.
AEP and Ameren also declined to comment. Ameren did note it is focused on executing its strategic plan, which is based on “strong organic growth” in its regulated businesses.
Evergy announced in early March that it had reached an agreement with Elliott to establish a new strategic review committee to explore ways to improve shareholder value. Elliott said at the time that Evergy is now “well positioned to significantly increase investment in critical electric infrastructure to benefit key stakeholders.”
Evergy also agreed to add two new independent directors to its board, raising the number of directors to 17. The board’s membership will be reduced to 13 by retirements before the May shareholders’ meeting.
The two new directors, former Energy Future Holdings senior executive Paul Keglevic and NRG Energy CFO Kirk Andrews, will comprise half of the Strategic Review & Operations Committee, which will look at “potential strategic combination(s)” or a modified long-term standalone operating plan. It can retain its own independent consultants, advisers and counsel to facilitate its review and has an information-sharing agreement with Elliott.
“Elliott recognizes our commitment to serving the best interests of all Evergy stakeholders,” Evergy CEO Terry Bassham said in the announcement. “We welcome these new, highly qualified directors and the significant and valuable experience they bring to this effort. The comprehensive strategic and operating review we are undertaking will help ensure that Evergy is directing capital to the greatest opportunities and continuing to consider all opportunities to enhance shareholder value.”
Evergy, an SPP member, was created in 2018 by a merger between Kansas City Power and Light and Westar Energy. It serves 1.6 million customers in Kansas and Missouri.
FERC said Friday that PJM must rebill parties with interest to reverse incorrect cost assignments for transmission projects to meet individual utilities’ planning criteria.
In 2015, the commission approved a PJM Tariff change that assigned 100% of the costs of Form 715 transmission projects to the sponsoring utility’s ratepayers. But FERC reversed itself last August after the D.C. Circuit Court of Appeals said it had erred.
The commission on Friday rejected rehearing on its August order and clarified that PJM should issue refunds dating back to May 25, 2015, with interest (ER15-1387-005, ER15-1344-006).
The commission rejected arguments by Linden VFT and Consolidated Edison Company of New York that the commission should have limited its remand order to high-voltage facilities.
Dominion Energy replaced a 500-kV line between the Cunningham and Elmont substations. | Dominion Energy
“PJM’s Tariff uses the solution-based DFAX [distribution factor] method to determine whether transmission facilities have benefits outside of the zone of the transmission owner constructing the project and allocates costs to zones based on the application of that methodology,” FERC said. “Because the benefits of lower-voltage facilities may accrue to other zones, we do not see a basis for limiting cost allocation for lower-voltage facilities planned under Form No. 715 local planning criteria to only the local zone of the constructing transmission owner.”
Linden also sought rehearing on the issue of refunds, arguing that the commission’s “default” policy is to reject refunds in cases of rate design.
The commission responded that it “does not have a general policy concerning refunds” but makes decisions based on each case individually.
“Here, the commission has found the facts and equities favor refunds,” it said. “For example, requiring refunds in this case requires only redetermining past payments; it does not involve the difficult issues often associated with the rerunning of auctions.”
PJM said it identified 443 transmission projects that had been assigned 100% to the zone of the TOs filing the Form 715 planning criteria between May 25, 2015, and the remand order on Aug. 30, 2019. It determined that it needed to revise allocations for 44 of the projects.
The new allocations reassigned costs for several projects in the Public Service Electric and Gas zone to Con Ed, East Coast Power, Neptune Regional Transmission System, Rockland Electric, PECO Energy and Jersey Central Power & Light.
Dominion Energy, which had been assessed for 100% of the rebuild of the Elmont-Cunningham 500-kV line, is now sharing the cost with 23 other utilities.
SPP stakeholders last week unanimously approved the initial set of protocols that will guide the RTO’s Western Energy Imbalance Service (WEIS) market in the Western Interconnection.
The Western Markets Executive Committee, meeting by phone on Friday, also formally disbanded the WEIS Protocol Review Task Force, which drafted the protocols. It will be replaced by the Western Markets Working Group, which has scheduled its first meeting for April 29. (See SPP Launches Western Market Groups.)
“I think [the protocols] are in a really good spot,” said SPP’s Gary Cate, who worked on the task force. “We know of some sections that need cleanup … but this is a living document. There are things in here that both the SPP team and the protocol team thought this is how the market should work. If we’re going to find it doesn’t work or what we thought is clear is not clear, we’ll clean those up or add new sections.”
The protocols’ settlements section and some formulas need to be revised, Cate said. Connectivity testing, market trials and parallel operations will likely highlight other revisions that need to be made, using a revision request process modeled on SPP’s.
To emphasize the point, David Kelley, SPP’s director of seams and market design, noted that the grid operator’s Integrated Marketplace protocols are currently in version 75.
“That gives you a flavor of how dynamic the protocols are,” Kelley told the committee. “You guys have the ownership of these protocols and this doc. It’ll change as often as you guys approve it to be changed.”
When it came time to vote, Chair Tim Vigil, with the Western Area Power Administration’s Colorado River Storage Project, asked whether committee members had any questions. He was greeted by dead silence, a sign of the impending vote.
The task force approved the protocols without opposition. Each of the companies on the committee also had a representative on the task force.
The WEIS market is scheduled to go live next February. SPP will centrally dispatch energy from the participants every five minutes to provide price transparency and bilateral trades.
