LITTLE ROCK, Ark. — SPP said Tuesday its wholesale electricity markets have reduced electricity costs by more than $1 billion since its Integrated Marketplace became operational in March 2014.
The RTO said it crossed the $1 billion threshold in September.
“Our markets provide tremendous value to the SPP region. That’s something we’ve known and demonstrated since they launched,” said Bruce Rew, SPP’s vice president of operations, in a statement. “The billion-dollar mark is an exciting milestone, and I’m proud that we reached it so quickly.”
SPP Control Room | SPP
SPP noted the milestone came just weeks before it celebrates its 75th anniversary. The organization formed in December 1941, when 11 utilities pooled resources to power an aluminum plant near Malvern, Ark., that supplied the Defense Department during World War II.
The RTO now numbers almost 100 members in all or part of 14 states.
“This is just one more example of the value that comes out of our stakeholder process,” said SPP CEO Nick Brown in a statement. “We’ve demonstrated through decades of success that our business model is built to stand the test of time, and we’ll keep on providing exceptional value and service to our members just like we’ve always done.”
After a brief discussion, the Markets Committee of the Board of Directors on Tuesday approved MISO’s forward auction proposal. The RTO expects a FERC filing in three weeks.
Director Baljit Dail said there was no reason not to go ahead with the filing date. “I think it was a very good piece of work,” he said.
MISO hopes the auction will ensure adequate capacity resources in Illinois and other retail-choice areas in the RTO’s footprint, most of which have traditional monopoly utility structures overseen by state integrated resource planning.
Director Michael Curran said he is “comfortable” with MISO’s plan for serving both structures. “I take a lot of comfort in the ability to look at metrics and adjust. I think as a community, MISO has adjusted a lot over the years, and it makes us successful,” Curran said.
Curran also thanked Independent Market Monitor David Patton for his recommendations and his “viable” alternative proposal. “I think he created a lot of healthy contention,” he said. Patton, who favors a prompt auction, has been sharply critical of MISO’s plan, calling it “fundamentally unsound.” (See MISO Backs Forward Auction Plan, Rejects Prompt Proposal.)
Director Phyllis Currie asked MISO staff how stakeholders view the proposal. Jeff Bladen, executive director of market services, said that while some stakeholders wanted more time for discussion, the majority “ultimately concluded they’ve had enough. … There remains some disagreement, as is expected in processes like these; consensus is nearly impossible to reach. The details of proposals like these are always ripe for disagreement.” (See “MISO to Move Ahead with Brattle Demand Curve for Forward Auction,” MISO Resource Adequacy Subcommittee Briefs.)
Bladen also said a “clear majority” of stakeholders agree that a problem exists in MISO’s retail-choice areas. He also pointed to the two years spent on the proposal. The RTO used 2015 to define the problem and gather ideas from members and the Monitor and worked to refine the proposal over 2016.
A few stakeholders, however, used the meeting’s public comment period to express concern.
David Sapper, representing the Transmission-Dependent Utilities sector, said MISO has only released draft — and not final — Tariff language. “With all due respect, I still think there’s some uncertainty on the proposal,” Sapper told the board.
Jim Dauphinais, counsel for Illinois Industrial Energy Consumers, agreed: “There are just going to be some details that have to be worked out by FERC.”
Curran asked about MISO’s ability to adjust the auction after it is fully implemented in 2019. Bladen said the RTO could consider changes as soon as the transitional auctions planned for 2018.
Dail asked if MISO was confident in The Brattle Group’s modeling, which left out MISO South. Bladen said while MISO South was “not explicitly modeled, it was implicitly modeled” through “stress tests” of various levels of non-merchant offers into a hypothetical forward auction.
Currie asked if the modeling anticipated future transmission additions. Bladen said while specific transmission projects or transmission topology changes weren’t modeled, greater and reduced import/export transmission capability was analyzed.
Director Paul Feldman asked if PJM’s forward auction might inform MISO’s, and if the RTOs plan to schedule their auctions at the same time. Bladen said he wasn’t sure how the auctions would interact because MISO was still so early into the process. “We’ve got some time ahead of us for coordination with PJM. I’m not in a position to recommend something now,” he said.
Ohio regulators Wednesday rejected FirstEnergy’s request for an annual $558 million rider for eight years, voting instead to give the company $204 million annually for only three years.
FirstEnergy, whose request would have totaled $4.46 billion, will receive $612 million (nominal dollars) under the unanimous decision by the Public Utilities Commission of Ohio.
FirstEnergy has 1,360 employees at its Akron, Ohio, headquarters. The company says its total economic impact in the state is $568 million annually.
The company said the eight-year retail rate stability (RRS) rider was necessary to ensure the corporation’s financial health at a time in which its coal- and nuclear-fueled generation is challenged by low natural gas wholesale energy prices.
The staff’s proposal “will provide FirstEnergy with an infusion of capital so that it will be financially healthy enough to make future investments in grid modernization,” the commission said in a statement. The commission’s unanimous order limited the rider to three years, with the possibility of a two-year extension.
Chairman Asim Z. Haque said the rider is not meant to solve all of FirstEnergy’s financial problems.
“If FirstEnergy truly needs $4.5 billion to achieve full financial health, then the commission decision today falls well short of that expressed need,” he wrote in his concurring opinion. “The commission does not intend to be, nor will it be, nor should it be the entire solution for FirstEnergy’s current financial difficulty. … The commission is an economic regulator. It is not a bank. It is not a trust fund. We authorize rates and charges that come directly from the pockets of consumers and businesses in this state. We have no rainy day fund to dip into.
“I do, however, want our regulated utilities to be healthy so that they can invest in bettering the delivery of services to consumers and businesses in the state of Ohio,” he went on. The rider “is meant to assist FirstEnergy in deploying the grid of the future while simultaneously providing it with a boost to improve its credit rating and financial health.”
FirstEnergy Unhappy
FirstEnergy will collect $132.5 million a year, with the balance of the $204 million going to taxes, said company spokesman Doug Colafella. Haque concurred with that figure “assuming current tax rate.”
The charge will boost monthly bills $3 (about 3%) for a typical residential customer using 750 kWh, the company said.
The company was not pleased with the decision.
“Today’s decision is disappointing for our customers,” said CEO Charles E. Jones. “While we clearly demonstrated to the PUCO what is essential to ensure reliability for customers in the future, the amount granted is insufficient to cover the necessary and costly investments. The decision also fails to recognize the significant challenges that threaten Ohio utilities’ ability to effectively operate.”
FirstEnergy said it is evaluating the order and considering its next steps. It has 30 days to appeal.
The modified RRS was FirstEnergy’s latest attempt for a state bailout. Its first attempt, submitted as a power purchase agreement, was approved by PUCO but collapsed after FERC said it — and a similar deal involving American Electric Power — would be subject to stringent reviews. (See FERC Rescinds AEP, FirstEnergy Affiliate-Sales Waivers.)
FirstEnergy and AEP went back to the drawing board. While FirstEnergy went with the modified rider request, AEP has chosen to go a different route: It is currently working with Ohio legislators to reverse customer choice and reregulate the industry.
Opponents also Miffed
Environmental groups and consumer advocates argued that the FirstEnergy request was unreasonable.
“Today’s decision takes hundreds of millions of dollars out of customers’ pockets in order to create a massive slush fund for FirstEnergy Corp. and its shareholders,” said Shannon Fisk, attorney at the nonprofit environmental law firm Earthjustice.
“The fact that FirstEnergy asked for billions more does not make this decision any less unreasonable. Rather than forcing customers to prop up profits for a corporation that made a bad bet on aging coal plants, the commission should be looking after customers and ensuring investments in job-creating renewable energy, energy efficiency and smart grid initiatives.”
The Sierra Club said PUCO could have used the ruling to encourage FirstEnergy to make further efforts to move toward more renewable energy.
“In this long-awaited and complicated decision, PUCO missed a critical opportunity to seriously focus FirstEnergy on the more diversified, cleaner energy future that tens of thousands of customers wrote the commission asking for,” said Dan Sawmiller, senior representative for the Sierra Club’s Beyond Coal campaign in Ohio.
“A few months ago, FirstEnergy took an important step in moving beyond coal when it announced closure of four units at its Sammis coal plant. With PUCO’s decision now issued, we hope to be able to work with FirstEnergy to accelerate its path beyond coal and nuclear and toward new investments in clean energy, energy efficiency and other modern grid initiatives like infrastructure for electric vehicles.”
IPPs Weigh in
The Alliance for Energy Choice, an organization funded by independent power producers, said FirstEnergy is still getting a good deal at ratepayers’ expense.
“The PUCO once again granted the utility’s request for more money with no corresponding benefit to customers,” Alliance spokesman and former PUCO Chair Todd Snitchler said. “Businesses and families will again be required to pay more for the same service they already receive with only a hope that customers will gain an upgraded grid if and when the utility elects to do so.”
“FirstEnergy should simultaneously be required to file a distribution rate case to document the need for, and amount of, a true grid modernization program,” Snitchler said.
Consumer advocate Public Citizen on Tuesday protested Energy’s proposed sale of the James A. FitzPatrick nuclear plant to Exelon, saying the companies’ FERC application failed to include information about the state subsidy that makes the transaction possible (EC16-169).
Public Citizen says omission of the subsidy makes the application incomplete. It also said the subsidy itself distorts the New York market and violates the NYISO Tariff.
“Exelon’s application to acquire FitzPatrick must be considered incomplete because, inexplicably, it fails to incorporate any mention or analysis of New York’s proposed ZEC payment subsidy scheduled only for FitzPatrick and for both of Exelon’s two in-state nuclear facilities. This payment subsidy, estimated at a total of $8 billion in six two-year increments, will significantly distort the NYISO energy and capacity markets and fundamentally alter the economics of Exelon’s power generation operations in NYISO, including FitzPatrick,” Public Citizen wrote.
“We believe the structure of the ZEC may conflict with elements of the NYISO … Tariff, particularly FERC’s mandate for incentives through the NYISO installed capacity market,” the protest continued.
“While the … proponents claim the ZEC is designed to combat climate change, a realistic analysis shows that the primary purpose of the ZEC is to keep select economically uncompetitive nuclear power plants operating, regardless of the impact on greenhouse gas emissions. And the state’s decision to discriminate between different nuclear generating stations for reasons other than climate change or the environment further complicates the true purpose of this expensive ZEC subsidy,” Public Citizen says.
Entergy’s downstate Indian Point facility, which is not financially stressed, is not currently eligible to participate in the ZEC program.
Opponents of the subsidy say it will cost ratepayers up to $8 billion over its 12-year life. Supporters say the state will enjoy a net economic benefit when it is calculated using the federal social cost of carbon analysis.
Public Citizen wants FERC to declare the application incomplete, require a market analysis that incorporates the full impact of ZECs and determine if the subsidies conform with FERC rules.
Public Citizen was the only party to file responses to the application before the comment deadline expired Oct. 10, except for U.S. Rep. John Katko (R-N.Y.), who sent a letter to FERC urging action on the deal. Katko, whose district includes FitzPatrick, said the plant provides more than 600 jobs and is “a vital part of the region’s economy.”
SPP’s Exit Study Task Force, formed to provide technical support and advice regarding Lubbock Power & Light’s move to ERCOT, conducted its first meeting last week.
The Public Utility Commission of Texas asked SPP and ERCOT to work together to study the implications of LP&L’s plans to migrate 430 MW of its load from SPP to ERCOT in June 2019. (See Texas PUC OKs ERCOT, SPP Studies on Lubbock Move.)
One issue is who will pay for the studies. PUC Chair Donna Nelson has said the burden shouldn’t fall on ERCOT ratepayers, suggesting during a Sept. 22 meeting LP&L should either fund the work or that the issue should be open “pending the outcome of the studies.”
“‘Depending on the outcome’ … I don’t know what that means,” said LP&L legal counsel Chris Brewster during the task force’s first meeting Friday.
Oklahoma Gas & Electric’s Jake Langthorn, the group’s chair, told the group the study costs will become clear once the scope and schedule are developed. SPP staff will begin its assessment by using its normal base cases from its near-term and 10-year studies.
“We’ll evaluate the system with Lubbock in SPP and without. In each case, we’ll evaluate the system against SPP planning criteria and NERC criteria to see whether we’re outside the acceptable ranges,” said Antoine Lucas, SPP’s director of transmission planning. He said the study will seek to identify any new transmission projects needed — or planned projects that can be deferred — as a result of Lubbock’s move.
LP&L representatives pushed SPP, which has targeted an April completion date, to accelerate its timeline.
ERCOT has said it will complete its assessment by the end of the year.
SPP says its existing planning workload will keep it from completing its work by the end of the year as ERCOT has promised.
“Having said that, we’re expecting it’s more than 90% in place right now,” said Lanny Nickell, SPP’s engineering vice president. “Once we put the schedule together, we can identify when we need it 100% finalized.”
SPP staff said it is meeting with ERCOT staff next week to review all questions posed by LP&L.
The task force is composed of four members of the Strategic Planning Committee and two each from the Transmission and Economic Studies working groups.
Wind, Coal Generation Continue to Rise, Fall
| SPP Market Monitoring Unit
Wind energy continues to rise in the SPP footprint and coal-fired generation continues to drop, according to the Market Monitoring Unit’s State of the Market report for this past summer.
The MMU said wind generation accounted for more than 12% of all energy produced in 2016, compared with 10% in 2015 and 9% in 2014. At the same time, coal generation’s share dropped to 51%, down from 62% in 2014.
Natural gas prices rose from this spring’s record low levels, the MMU said. The average price at the Panhandle Hub was $2.51/MMBtu this summer, compared with $2.60/MMBtu in 2015 and $4.00/MMBtu in 2014.
| SPP Market Monitoring Unit
The “wind alley” of the Texas panhandle, western Oklahoma and western Kansas continues to experience most of the SPP footprint’s congestion. However, the MMU said, congestion has increased in southeast Kansas and parts of Arkansas, which it attributed to higher summer loads and planned generation and transmission outages.
Staff will review the submittals and share them at their next Interregional Planning Stakeholder Advisory Committee meeting.
SPP staff said a joint model is being developed, but it will likely have differences with each RTO’s regional models, and that some of the identified regional needs may not show up in the model.
Separately, SPP and Associated Electric Cooperative Inc. have developed models and assessed the needs for the target areas, posting them to allow stakeholders to submit solutions. The two organizations requested input be submitted by Nov. 7.
SPP Interregional Coordinator Adam Bell told the committee the Northeast Oklahoma target area will no longer be evaluated in the SPP-AECI joint study because of a change of power suppliers in the region. He said the change “resulted in there no longer being potential needs observed on both sides of the SPP-AECI seam.”
VALLEY FORGE, Pa. — After months of debate on proposed definitions for operating parameters, PJM and the Independent Market Monitor rankled some Market Implementation Committee members last week by introducing an unexpected, last-minute compromise package that included one key change but largely maintained the status quo.
The proposal leaves many of the definitions untouched, except for minimum runtime and soak time. The endorsed definition of minimum runtime replaces a unit’s “breaker closure” with simply when a unit is “dispatchable” as the starting point. It also “un-nests” soak time from minimum runtime, differentiating it as its own parameter.
“We think it’s a big step forward,” Monitor Joe Bowring said.
Several stakeholders said they wouldn’t have enough time to give the proposal a reasonable review that day, but a seconded motion to vote on the issue forced them to act. The vote, which was planned for the morning session, was delayed until the afternoon to provide extra time.
| PJM
It was enough: The joint package received support from 75% of stakeholders — far exceeding competing proposals. It also won more than 60% support in a head-to-head vote against the status quo, meaning it will be forwarded to the Markets and Reliability Committee. (See “Members Hear First Read on Plan to ‘Un-Nest’ Operating Parameters,” PJM Market Implementation Committee Briefs.)
The last-minute proposal by PJM and the Monitor caused several stakeholders to question the functionality of the stakeholder process. “Do we just not care about the stakeholder process anymore?” Ed Tatum of American Municipal Power asked during the initial discussion. “What’s the idea of bringing something that no one’s been able to look at?”
After the vote, PJM’s Dave Anders thanked the members “for working through the issue.” He acknowledged their frustration, but he said this was an example of “the stakeholder process actually working.”
He invited members who have thoughts on reforming the process to attend the Stakeholder Process Forum Oct. 24.
Stakeholders Debate ARR Changes
In response to a problem statement approved earlier this year, PJM has begun revisiting its procedures for allocating residual auction revenue rights and hopes to file a solution with FERC on Dec. 31.
Exelon and Direct Energy issued a proposal last week for reducing potential revenue fluctuations under the current allocation. Their proposal would eliminate any residual ARR paths that could receive negative values based on monthly financial transmission rights clearing prices. PJM would then rerun the simultaneous feasibility test before allocating residual ARR megawatts for the month.
PJM’s proposal would give stakeholders the opportunity to opt out of allocations on a path-by-path basis. Sharon Midgley of Exelon said both proposals solve the issue but differ on the approach taken to address the current forced allocation of negative paths to customers. The Exelon/Direct Energy package puts an additional administrative requirement on PJM, while the RTO’s proposal places new analytical requirements on load-serving entities.
PJM’s Asanga Perera explained that the stakeholder proposal puts a heavy burden on PJM staff to process the data for negative pathways within a few days to have the results back to stakeholders in time for the next round of ARRs. He said it creates the potential for PJM to miss a deadline and leave stakeholders without the information necessary to identify negative pathways.
He pointed out that the process for stakeholders under PJM’s plan uses what they already do for the annual ARR process.
However, several stakeholders criticized PJM’s plan, saying their companies don’t have the staff to analyze the thousands of potential pathways each month. “I think PJM’s proposal with the burden placed on the stakeholders, that would be too overwhelming,” said a stakeholder who asked not to be identified. “It would give an advantage to the stakeholders that have the staff and the resources available to do that.”
PJM Looks to Revise Shortage Pricing Procedures
PJM’s Adam Keech presented a shortage pricing proposal to avoid potential volatility posed by implementation of FERC Order 825 (RM15-24).
Under the order’s transient shortage pricing rules, even brief shortages will trigger the maximum penalty factor, which could cause volatility as market participants attempt to respond. (See FERC Issues 1st RTO Price Formation Reforms.)
PJM’s proposal would create steps below the maximum penalty factor based on historical performance so that the maximum penalty does not apply until the reserve is down to the largest single resource’s actual output as opposed to its economic maximum. The measurement would change every five minutes.
Keech noted that in the past 21 months, PJM has observed 845 instances where, under the rules in Order 825, reserve prices would have hit the maximum $850/MWh penalty factor in the Mid-Atlantic and Dominion regions. He hadn’t analyzed the data enough to explain why 759 of them were in 2015 compared with 86 in 2016.
Stakeholders endorsed by acclamation changes to PJM’s credit policy. The revisions to Attachment Q of the Tariff reorganize provisions and make five minor changes to them, none of which affect credit requirements, according to PJM’s Harold Loomis.
The changes also specify that collateral may not be encumbered or restricted and provide PJM “reasonable time” to investigate breaches of credit requirements before implementing remedies, ensuring the RTO’s action is not foreclosed if it does not act immediately.
The revised attachment also replaces a section on peak market activity (PMA) collateral requirements with one specifying PMA credit requirements.
‘Working Groups’ Removed from MIC Charter
Stakeholders endorsed edits to the MIC charter that removed references to “working groups,” as they no longer exist. Working groups were eliminated as part of a larger reorganization of the stakeholder process starting in 2009 that standardized the purposes for and creation of task forces and subcommittees.
Stakeholders Develop Interest List for Black Start Requirements
PJM is soliciting stakeholder feedback on the priorities that should be considered in developing annual revenue requirements for new black start units. The current interest identification includes 13 concerns, including that the Monitor calculate revenue within six months of units entering black start service.
Bowring said the calculations can’t be made without explicit documentation to support “every penny of requested revenue changes” and that documentation must be submitted in a timely fashion. Members asked Bowring to specify what documentation is required.
FERC has been ordered to pay attorney’s fees for stonewalling an energy trading company’s request for documents under the Freedom of Information Act.
Bates | District Court of DC
While the award — $60,168 — was not huge, the fact that a U.S. District Court judge ruled against FERC was unusual.
Kevin and Rich Gates, acting as principals of the energy trading company STS Energy Partners, filed FOIA requests seeking documents related to investigations by FERC’s Office of Enforcement into two other energy trading companies, Oceanside Energy and Black Oak Energy.
The Gates brothers, who have been involved in a very public battle with FERC over market manipulation allegations against one of their other companies, Powhatan Energy Fund, said in filings that they wanted the documents “to shine light on FERC’s recent and punitive efforts against small power market traders for engaging in legal and ubiquitous activity.” They have accused FERC of withholding information before. (See Gates, Powhatan Say FERC Enforcers Didn’t Share Crucial Info.)
FERC eventually produced the information STS had asked for, but the two sides couldn’t agree on the attorney’s fees issue, and it was argued in D.C. District Court.
In his Oct. 5 ruling, Judge John D. Bates noted that the award of legal fees can serve two purposes: encouraging FOIA suits that benefit the public, and compensating plaintiffs for “enduring an agency’s unreasonable obduracy in refusing to comply” with FOIA requirements.
Bates noted that “FERC did show some recalcitrance and at least ‘appeared’ to ‘withhold’ the segregable portions of requested documents merely to avoid embarrassment or frustrate the requester.”
The commission initially issued “blanket denials” for the 41 documents related to the Oceanside investigation and the 294 records identified in the Black Oak case, Bates noted.
FERC released several documents after STS filed suit over the denial, and it released all or parts of 115 documents after the court denied the agency’s summary judgment motion. The commission reached a settlement with the company over the remaining documents in May 2015.
Bates said the agency’s contention that the requested information could not be culled out, or “segregated,” was not a “reasonable basis in law.”
“Nor can FERC prevail on the reasonable basis factor by deciding to release the documents only after forcing the requester to sue,” he wrote.
The brothers have asked the U.S. District Court for the Eastern District of Virginia to allow it to defend itself against FERC’s allegations in a jury trial (3:15-CV-00452-MHL).
VALLEY FORGE, Pa. — PJM has found a way to provide generators with the performance assessment hour alerts that owners requested, but it’s not going to be easy.
The problem is how to get the PAH alerts from PJM’s emergency procedures channel to the Inter-Control Center Communication Protocol (ICCP) and Distributed Network Protocol channels that unit operators say they monitor with far more frequency. The process would translate the emergency procedure signal into a yes or no signal for each resource.
“We can do it. It’s not the prettiest thing,” PJM’s Rebecca Stadelmeyer told the Operating Committee last week. “This is not an easy plug and play. This is a lot of systems actually talking together, even though it sounds like it’s just a simple output. To get there is going to take us some time and some money.”
The minimum estimate of eight months and $150,000 is expected to increase as outside vendors are contracted and PJM staff are redeployed from other major projects, she said. The cost of the changes means that other projects that were already planned may be delayed.
There may be additional costs for generators to make updates to properly receive the signals.
Brock Ondayko of American Electric Power pointed out that PJM has had since at least April to integrate this request into its budgets and avoid any interference with other projects. (See “PJM Considering Notification of Performance Assessment Hours,” PJM Markets & Reliability and Members Committees Briefs.)
“Maybe there needs to be a better mechanism to describe things that stakeholders are asking for to be considered in the budget for the following year,” he said.
All generating units above 100 MW have ICCP access to receive the upgraded signals, PJM confirmed. Those without the feeds will only be able to receive PAH alerts through the emergency procedures channel.
The RTO must map every resource to each region, transmission owner zone and sub-zone. Stadelmeyer warned that units won’t be excused from nonperformance penalties that arise from incorrect mapping or “broken signals” stemming from owners’ failure to make changes needed to receive the signals.
PJM’s request for feedback on whether to move forward with the plan failed to muster much enthusiasm, even with committee chair Mike Bryson twice stepping in to solicit comments. Finally, Sharon Midgley of Exelon said her company is “very much interested” in the project being completed despite the complications. Jim Benchek of FirstEnergy also offered support, but he cautioned that “the devil’s in the details” on the project’s cost-benefit ratio.
The development of the project will likely be tracked through PJM’s new Tech Change Forum, Bryson said.
Jorge Bermudez has resigned from one of five unaffiliated positions on ERCOT’s Board of Directors after his recent marriage triggered a conflict of interest.
Bermudez’s wife is an officer with an ERCOT market participant affiliate, Citibank. The affiliate is not directly involved in the ERCOT market, but the ISO’s bylaws outline a number of stringent requirements for unaffiliated directors. ERCOT said its legal department determined the relationship to be a conflict “based on those requirements.”
“We have no reason to believe at this time that this conflict resulted in any inappropriate actions during his service to the board,” ERCOT spokesperson Robbie Searcy said. The ISO’s board Tuesday will vote again on any matters that Bermudez participated in during its August meeting “to ensure all board actions of record are consistent with these bylaws,” she said.
“For some odd reason, he chose his wife over ERCOT,” joked Texas Public Utility Commissioner Ken Anderson during the commission’s open meeting Oct. 7.
Anderson and his fellow commissioners closed the meeting by heaping praise on Bermudez. The PUC has regulatory oversight of ERCOT and approved Bermudez’s selection to the board in September 2010.
“He’s such a tremendous gentleman, but what are you going to do with kids today? They run off and fall in love,” Commissioner Brandy Marty Marquez said. “It’s sad to lose him.”
In a statement, ERCOT CEO Bill Magness said Bermudez’s “expertise and careful deliberation, particularly regarding financial matters, will be missed greatly.”
Under ERCOT’s bylaws, the board’s Nominating Committee will select and vote on his replacement, retaining an executive search firm to begin the candidate selection process. The candidate must be approved by both the ISO’s membership and the PUC, with the latter’s approval coming “within a time frame that will … avoid or minimize the length of unaffiliated director vacancies on the board.”
Candidates must have experience in one or more of the fields of: senior corporate leadership; professional disciplines of finance, accounting, engineering or law; regulation of utilities; risk management; and information technology. Candidates must be independent of any ERCOT market participants.
Bermudez had 33 years of experience with Citigroup, retiring in 2008 as chief risk officer. He is currently CEO of the Byebrook Group , a research and advisory firm in the financial services industry.
336 MW of Wind and Solar Added in September
An additional 336 MW of wind and solar began operating in September, according to ERCOT’s latest generator interconnection status report. The new additions were:
Duke Energy Renewables’ 110-MW Los Vientos wind farm in South Texas;
Invenergy Wind’s 120-MW Gunsight Mountain Wind Farm in West Texas; and
OCI Solar Power’s 106-MW facility, contracted to San Antonio’s CPS Energy, north of Abilene in West Texas
The ISO now has 25,254 MW of wind capacity and 9,391 MW of solar power operating, under study or with signed interconnection agreements.
The additional capacity helped ERCOT set new demand records for October with peaks of 59,359 MW and 59,909 MW, respectively, during the late-afternoon hours of Oct. 5. The Texas grid operator’s final Seasonal Assessment of Resource Adequacy for October and November had projected a peak demand of 54,400 MW this fall.
VALLEY FORGE, Pa. — PJM is considering a significant increase in the performance participation threshold for participants in its regulation market.
The current minimum participation threshold of 40% may be increased to 75%, RTO officials told the Operating Committee meeting last week. Each unit is evaluated for participation based on its average scoring over the past 100 hours of regulation service on three components: precision, accuracy and delay.
| PJM
American Electric Power’s Brock Ondayko said increasing the participation thresholds could have a major impact on the number of megawatts available to respond, noting that steam units, which make up the vast majority of RegA participants, average a 75% performance score.
As part of a quarterly report on regulation performance, PJM’s Eric Hsia provided a graph of participants’ average performance and frequency of participation. The results provided a stark contrast between participation in RegD — a dynamic regulation signal meant to stabilize constant frequency deviations — and RegA, a signal that is sent every four seconds.
Regulation-capable units that accept the offered price for participation are expected to align their output with the signals they receive from PJM. The RTO’s data show that, while there is far more participation in RegA, participants in RegD participate far more often.
Responses Hard to Predict
PJM said it is seeing wide variability in primary frequency response between evaluated frequency events, with many generators either not responding, withdrawing responses or responding in the opposite direction — decreasing output, for example, when frequency declines. Additionally, a “significant portion” of primary frequency response is coming from load, which can’t be predicted or controlled, PJM’s Danielle Croop said.
It’s a “roll of the dice” every time to see what’s going to happen, she said. Croop presented several graphs of units’ responses to recent frequency response events that showed the units either not responding, stopping their response, not providing sustained response or responding in the opposite direction.
One potential cause of the erratic performance is that a unit’s “operating control mode” is following some other indicator and not in droop mode allowing them to respond to frequency deviations, she said. Units that don’t respond at all might be operating in modes or with governor settings, that don’t allow for response — or have their governors turned off altogether, she added.
About 69% of frequency response in 2016 has come from coal-fired units, Croop said. In response to a question from Ondayko, she speculated that the participation level of natural-gas-fired units at just 19% was likely due to three factors:
Units must be on the grid to provide frequency regulation, so fast-response natural gas units that run sporadically often won’t have an opportunity to get involved;
Control systems might be “squelching” or preventing the response; or
Units might be operating so close to their maximum capacity that they don’t have much room to adjust.
Units that are providing regulation are not expected to also provide primary frequency response, Croop said, and so aren’t calculated into PJM’s expected performance.
