The Gulf Coast Power Association will honor former Executive Director Tom Foreman with its 2019 Pat Wood Power Star Award during its spring conference in Houston next month. The award is presented in recognition of the recipient’s “significant contributions towards the advancement of [Texas’] competitive energy markets.” Foreman retired as GCPA’s executive director last year, capping a 41-year career in the utility industry. (See GCPA’s Foreman to Retire as Executive Director.)
“Throughout his long career in the Texas power market, Tom Foreman has been a thoughtful, inclusive, creative and loyal friend to so many of us,” said the award’s namesake, former FERC Chairman Pat Wood III. “Under his leadership, the GCPA has grown to its largest and most diverse membership in history. Tom Foreman is an exemplary Power Star.”
Foreman served as the organization’s third executive director from 2013-2018. During his tenure, GCPA launched its emPOWERing Women program and expanded the organization’s geographic reach with conferences for electric markets in states and countries bordering Texas that are evolving competitively. The association will hold its fourth Mexico Electric Power Market Conference on June 6 in Mexico City. GCPA also donated approximately $500,000 to universities during Foreman’s tenure.
Tom Foreman | GCPA
“Tom has done an outstanding job by expanding into other regions, establishing the emPOWERing Women program and growing the scholarship program,” said Kim Casey, who succeeded Foreman as executive director.
Foreman began his career at Gulf States Utilities in Beaumont, Texas. He consulted in Austin before spending 23 years with the Lower Colorado River Authority, followed by his six-year stint with GCPA. He holds bachelor’s and master’s degrees in engineering from the University of Texas at Austin.
Wood, who also chaired Texas’ Public Utility Commission under Gov. George W. Bush, will be on hand to help present the award during GCPA’s 33rd annual Spring Conference April 16-17.
WILMINGTON, Del. — Stakeholders on Thursday reluctantly agreed on a path forward for PJM’s proposed “fuel security” initiative after about two hours of debate over whether RTO officials have already decided the outcome.
The Markets and Reliability Committee approved a compromise problem statement and issue charge, adding a requirement that PJM quantify the likelihood of scenarios that might present a risk of fuel insecurity.
Stakeholders also rejected PJM’s proposal to complete work on the issue by the end of the year. Instead, stakeholders will complete their initial research by the end of August and the MRC will set a final deadline for action — if any — at its September meeting.
Members also added language to the issue charge to consider the market responses to conditions that could lead to fuel insecurity and assess whether the current market construct is sufficient to cure the problem.
The compromise was approved by acclamation with one objection.
‘Stress Test’
Critics have complained the initiative is yet another effort to provide additional compensation to coal and nuclear generators, following failed efforts by President Trump and Energy Secretary Rick Perry.
PJM issued a study last year that showed the RTO could face outages under extreme winter weather, gas pipeline disruptions and “escalated” resource retirements. The study, which evaluated more than 300 winter scenarios, was a “stress test … intended to discover the tipping point when the PJM system begins to be impacted,” the RTO said. (See Full PJM Study Makes Case for Fuel Security Payments.)
Marji Philips, Direct Energy
Marji Philips of Direct Energy said PJM’s proposed December 2019 filing deadline was “suspicious.”
Philips said she agreed on the need for an end date but said the 2019 target “tells me it’s not going to be a meaningful process.”
Bob O’Connell of Panda Power Funds said a “fundamental flaw” in PJM’s proposal is that its analysis made no effort to quantify the risk of the dire scenarios it outlined. He disputed the RTO’s claim that all of its scenarios are “plausible.”
“Many of us … believe that the risk of some of these scenarios is a decimal point, six zeroes and a one,” he said.
O’Connell also disputed PJM’s assertion that it has not identified any solution.
Bob O’Connell, Panda Power Funds
He cited an interview PJM CEO Andy Ott recently gave to Bloomberg in which he said the region’s gas units have 30 to 40 hours of backup fuel and that “what we need them to keep is about five days.”
“That sounds like a solution to me,” O’Connell said. “What’s left for the stakeholders is just fighting over how to pay for it.”
PJM’s Tim Horger said later that incorporating a probabilistic analysis would be “challenging.”
“I don’t know if it’s feasible,” he said.
Tim Horger, PJM
Jim Wilson, a consultant to state consumer advocates, also expressed skepticism about such an analysis. “Probabilistic analyses usually rely on historical data. [The fuel security analysis] is based on events that have never occurred,” he said, citing an example of a terrorist attack on a natural gas pipeline.
“I don’t think we should focus a lot of effort on this … because it will necessarily rely on speculative assumptions,” he said.
Philips and David “Scarp” Scarpignato of Calpine questioned the value that fuel-secure nuclear plants bring the RTO when they often shut down in advance of a major storm.
Jason Barker of Exelon said the issue of nuclear shutdowns is irrelevant.
Jason Barker, Exelon
“It mixes reliability analysis and PJM’s request to address fuel security,” he said. “If this [inquiry] becomes too broad, we’re setting ourselves up for failure.”
Paul Sotkiewicz, PJM’s former chief economist, said the RTO’s study predicted load shed could result from an “inordinate amount” of plant retirements but failed to consider how the market would respond to so many plant closures.
“None of that analysis has been done,” he said. “The current market design may be able to handle this under Capacity Performance.”
Ott Interview
In the interview on Bloomberg’s “Commodities Edge” show, Ott said the initiative should determine the cheapest way to provide the security of natural gas plants with five days of backup fuel.
“What the vulnerability is … the gas units keep about 30 to 40 hours of onsite fuel. What we need them to keep is about five days. So the point is there’s got to be an infrastructure build if we’re going to use those resources as firm fuel supply resources. … Either larger on-site fuel storage, or we buy more fuel trucks to say they’re on standby essentially to deliver fuel more dependably in the winter.
“The other alternative, of course, is to say what’s that money spend, and is it cheaper than to keep the nuclear plant or keep the coal plant? … It’s going to be an economic decision, and the best technology will win.”
Ott said PJM expects 18,000 MW of coal retirements over the next five years and could sustain as much as 30,000 MW. “If it gets beyond that, we start to look at what are the alternatives?
“A gradual transition we can easily deal with over time. What folks are worried about, and what the U.S. federal government is worried about, is if there going to be an abrupt change.”
Wilmington, Del. — PJM on Thursday offered stakeholders four options for navigating its upcoming capacity auction, noting that each comes with risks and uncertainties.
“We are in a bit of quandary,” said Stu Bresler, PJM’s vice president of operations and markets. “There really are no obvious good answers as to how we can move forward at this point. I think it falls into the lesser of two evils category.”
Bresler’s comments come on the heels of PJM’s filing with FERC urging guidance for the Aug. 14 Base Residual Auction, given a previous commission decision that the RTO should revamp its minimum offer price rule (MOPR) to address price suppression resulting from rising state subsidies for renewable and nuclear power (ER18-2222). PJM filed changes in October and had hoped for a FERC response by March 15 to no avail. (See PJM to FERC: Hurry Up with Auction Guidance.)
“Absent from any other order from FERC in this regard, we are obligated to follow the Tariff,” Bresler told the Markets and Reliability Committee on Thursday.
The Choices
Bresler presented the four paths PJM staff identified as viable and solicited feedback from the MRC on each of them, including:
Move forward with existing rules and accept the possibility that FERC will retroactively apply new rules, forcing PJM to rerun the August BRA.
File a waiver with FERC to delay the BRA until closer to the May 2020 auction, noting FERC has no timeline for ruling on such a request.
File a request for FERC to confirm existing rules for the interim, eliminating the risk of re-rerunning the auction after the commission decides on the MOPR. Bresler noted this option has very little chance of success.
Present an alternative interim rate in a Section 205 filing that would sunset after the August BRA, eliminating the risk of having to re-execute the auction at a later date. This type of filing bakes in a 60-day timeline for FERC to issue guidance but may require stakeholders to follow a “parallel path” in case FERC denies the filing.
Bresler said staff will return to the April 10 meeting of the Market Implementation Committee with its agreed-upon path forward.
“I don’t think there’s a drop-dead date [for delaying the auction],” he said. “But with some of these other options, the sooner the better.”
Stakeholders Torn
The anxiety expressed by stakeholders at the March 6 MIC meeting carried forward into Thursday’s MRC, with representatives across the board abandoning hope of a short-staffed FERC offering guidance anytime soon. (See FERC’s McIntyre Loses Cancer Battle.)
“One of the things we keep going back to is the uncertainty of when actual action will be taken,” said Neal Fitch, of NRG Energy, noting a fifth commissioner — capable of breaking any deadlocked rulings — has yet to be named. “We think it’s right to move along with an auction in August … simply because we have no idea when FERC will act.”
Others argued that delaying the auction until next spring remained the only prudent choice and appeared unconvinced by PJM’s assessment that FERC is unlikely to force the RTO to re-execute the auction under new rules. The commission in January ordered PJM to rerun the July 2018 FTR auction to liquidate GreenHat’s FTR positions, which could add $250 million to $300 million to the already $186 million projected cost to members from the default. Last month, the RTO requested a stay of that ruling. (See PJM Won’t Act on FTR Order Before Stay Ruling.)
Carl Johnson, representing the PJM Public Power Coalition, argued delaying the auction could impact the market negatively.
“Without any guidance from FERC, you’re shooting in the dark,” he said. “I think the idea of putting together some interim [Section] 205 [filing] bridge to justness and reasonableness might have some attraction.”
WASHINGTON — FERC Chairman Neil Chatterjee on Thursday praised former Chief of Staff Anthony Pugliese, denying there had been any conflict between the two but also staying mum on the reason for his departure from the commission.
“I want to thank Anthony for his friendship, for his willingness to serve the agency and the country, and we wish him well in his future ventures,” Chatterjee said at the beginning of the commission’s monthly open meeting.
Pugliese announced his resignation via Twitter the day before, saying he was “grateful for the opportunity to serve [President Trump], [FERC] and the American people as chief of staff! Excited for my next challenge and opportunity — continuing the American model of energy for the world. Stay tuned! But first a little time for a vacation!”
Following his tweet, FERC made its own announcement, saying Pugliese’s resignation was effective March 15. In a press conference after the meeting, Chatterjee told reporters that he was planning to make the announcement himself during the meeting, but “I think some of you all maybe were starting to ask questions, [which] prompted his tweet.”
Chatterjee was reluctant to talk about the circumstances around the departure. But, he said firmly, Pugliese “was not asked to leave.” He declined to comment on the search for a replacement.
Pugliese told Politico on the day of his announcement that he had been planning on leaving since Commissioner Kevin McIntyre’s death in January.
A former lobbyist in Pennsylvania’s capital and an unsuccessful state legislative candidate there, Pugliese had served as chief of staff since August 2017, before the arrival of McIntyre as chair in December of that year. He stirred controversy last July for remarks he made at a conference of the American Nuclear Society and on the “Breitbart Radio Show,” in which he praised Trump and criticized Democratic governors for blocking pipelines.
In a letter to congressional Democrats, McIntyre defended Pugliese, saying his comments did not reflect FERC policy. After taking the role of chair because of McIntyre’s ailing health, Chatterjee in late October also defended Pugliese. Both praised Pugliese’s management and administrative skills. (See Returning Chair Pledges to Protect FERC’s Independence.)
Asked if his relationship with Pugliese had “deteriorated,” Chatterjee responded, “Look, Anthony is a personal friend of mine, and I don’t agree with that characterization.” He also declined to say what, if any, disagreements led to the resignation, repeating that Pugliese was a friend and that he wished him well.
Coal, Nuke Bailout Still Alive
Chatterjee also said he had never had any conversations with the White House during his nomination process about the Trump administration’s push to bail out uneconomic coal plants.
The question came in response to a Politico article published Tuesday reporting that Trump had dropped plans to nominate former NRG Energy General Counsel David Hill to fill McIntyre’s spot after pressure from Energy Secretary Rick Perry and coal company executives Joe Craft and Robert Murray. Hill, who was DOE general counsel under former President George W. Bush, had opposed the DOE’s effort to support coal generators.
The article came the same day the White House published its annual economic report, which contained a paragraph about “the strategic need for an electricity generation reserve.”
“The entire portfolio of generation assets in the United States could be eligible to be part of a reserve, with different strategic weights placed on various types of generation — for example, nuclear or coal-fired generation might provide greater resilience benefits and therefore be preferentially selected into the reserve,” the report says.
WASHINGTON — FERC will seek comments on how it could improve its transmission incentives and return on equity policies under two Notices of Inquiry issued Thursday.
The commission will examine whether transmission incentives “should continue to be granted based on a project’s risks and challenges or … on the benefits that a project provides,” FERC said at its monthly open meeting (PL19-3).
Under the other inquiry, the commission will examine whether, and if so how, to change how it calculates ROEs for electric infrastructure, as well as for natural gas and oil pipelines (PL19-4).
“Given the complexity and scale of building new transmission projects, the decisions my colleagues and I make now will have impacts for decades to come,” FERC Chairman Neil Chatterjee said. “What all this boils down to is [that] getting these policies right will be critical to ensuring the energy revolution we’re currently undergoing results in more reliable services and lower prices for customers. To that end, I think the two NOIs we are issuing today are an important step toward getting our transmission policies right.”
Initial comments on both NOIs are due 90 days after their publication in the Federal Register, with reply comments due 30 days after that.
FERC noted in its transmission incentives policy NOI that 13 years have passed since it established its current policy in Order 679, after Congress in the Energy Policy Act of 2005 directed the commission “to promulgate a rule providing incentive-based rates for electric transmission for the purpose of benefiting consumers through increased reliability and lower costs of power.”
“During that time, the landscape for planning, developing, operating and maintaining transmission infrastructure has changed considerably,” FERC said, including issuance of Order 1000, the shift in the generation mix, the increase in the number of new resources seeking transmission service, shifts in load patterns and an increased emphasis on the reliability of transmission infrastructure.
“I believe we are really at an inflection point in the energy future of our nation, and FERC’s transmission policies are going to be key to shaping that future,” Chatterjee said.
Order 679 required “that each applicant demonstrate that there is a nexus between the incentive sought and the risks and challenges of the investment being made.” FERC asked stakeholders whether it should stick with this “risks-and-challenges” approach, if it should be retained while also considering other factors, or if it should just be replaced entirely. The commission asked stakeholders to weigh in on other approaches, such as considering the economic and reliability benefits of a project or considering project characteristics (such as location in areas of persistent need or interregional efforts) as a “proxy” to benefits.
Commissioner Cheryl LaFleur said she was particularly interested in comments on the transmission-only company and RTO participation adders, and on the interplay between the incentives policy and Order 1000.
“I do believe there’s a clear need to construct more transmission to ease the interconnection of location-constrained renewables,” LaFleur said. “And I think that’s evidenced by the choking interconnection queues in several of the regions, suggesting there might be transmission that’s needed rather than just hundreds of interconnections, and we have to make sure the processes support that.”
“It is not clear to me that in some cases the incentives we are handing out are actually incenting anything,” Commissioner Richard Glick said. “If we’re going to design the right approach, we need to be reasonably certain the incentives are necessary or whether the investments in question would occur anyway. In other words, we shouldn’t be handing out what some people refer to as ‘FERC candy’ without actually achieving something beneficial in return.”
The NOI on the commission’s ROE policies comes in response to the D.C. Circuit Court of Appeals’ 2017 ruling that remanded a FERC order setting the base ROE for a group of New England transmission owners at 10.57%. (See Court Rejects FERC ROE Order for New England.)
FERC set the ROE at the midpoint of the upper half of the zone of reasonableness produced by a two-step discounted cash flow (DCF) analysis. In Emera Maine v. FERC, the court found that FERC had failed to show how this was just and reasonable, though it did not challenge the commission’s methodology. Nevertheless, in October, FERC proposed a new policy for how it would set transmission ROEs, suggesting it would no longer rely solely on the DCF method. (See FERC Changing ROE Rules; Higher Rates Likely.)
The NOI issued Thursday will take a much broader look at FERC’s ROE policies, including whether any changes to its transmission ROE policies should be applied to interstate natural gas and oil pipelines. The commission noted that the NOI won’t affect the docket it opened in October, nor other current ROE proceedings.
“The commission recognizes the potentially significant and widespread effect of our ROE policies upon public utilities,” FERC said. “The importance of ROE policy for public utilities extends beyond the particular interests of the parties to the Emera Maine proceeding.”
FERC asks more than 70 questions in the NOI. In a press release, it divided them into eight general areas:
The role of FERC’s base ROE in investment decision-making and what objectives should guide the commission’s approach;
Whether uniform application of FERC’s base ROE policy across the electric, natural gas pipeline and oil pipeline industries is appropriate and advisable;
The DCF model’s performance;
The composition of proxy groups;
The choice of financial model used;
The mismatch between market-based ROE determinations and book-value rate base;
How FERC determines whether an existing ROE is unjust and unreasonable under the first prong of FPA Section 206; and
The mechanics and implementation of the models.
“The questions we ask are extremely detailed and comprehensive, and this has been a notoriously difficult area of our work, around which to develop a consensus and sustain in court,” LaFleur said. “I strongly encourage commenters to be focused and concise in their comments.” She stressed that commenters need not answer every single question.
FERC on Thursday ordered MISO (ER18-2397) and SPP (ER18-2318) to make additional Tariff changes to comply with the transparency requirements of Order 844 while approving PJM’s filing (ER18-2401).
Order 844, issued in April 2018, requires RTOs and ISOs to submit monthly reports detailing their uplift payments and operator-initiated commitments. The commission said that existing reporting practices were insufficiently transparent and caused unjust and unreasonable rates. (See FERC Orders RTOs to Shine Light on Uplift Data.)
PJM 2018 energy uplift credits changes by category, and change from 2017 | Monitoring Analytics
MISO Order
The commission disagreed with MISO’s decision to exclude price volatility make-whole payments from its zonal uplift and resource-specific uplift reports.
“We understand MISO’s argument to be that price volatility make-whole payments are not classified as uplift in Order No. 844 because they are not triggered by a specific reliability need. However, we disagree that such a narrow definition of uplift was implied by the statement in Order No. 844 that ‘uplift payments reflect the portion of the cost of reliably serving load that is not included in market prices.’”
The commission said the payments — intended to maintain resources’ incentives to follow dispatch signals and operator instructions — are uplift “because they provide economic incentives to resources to operate in a manner consistent with system needs at costs that are ‘not included in market prices.’”
It also directed MISO to replace the word “uplift,” which is not a defined term in the Tariff, with terms describing types of uplift that are defined, such as the day-ahead revenue sufficiency guarantee credit.
The commission agreed with MISO’s decision to use local resource zones (LRZs) — which are used to settle charges under the RTO’s resource adequacy process — for reporting purposes. But it said the RTO needs to explain how it will account for uplift paid to imports.
“We direct MISO to explain on compliance whether the commercial pricing nodes associated with imports are located within LRZs and how it intends to report uplift associated with an import if its commercial pricing node does not exist within a LRZ,” FERC said.
The commission also ordered MISO to amend its Tariff to include “as soon as practicable” similar language to describe the notice issued to market participants for temporarily changing transmission constraint penalty factor (TCPF) values.
FERC rejected a request by the Louisiana Energy Users Group and Texas Industrial Energy Consumers to require MISO to report by categories in its resource-specific uplift report. The industrial users contended that aggregating all uplift payments by resource does not provide enough information about the resource locations to address day-ahead voltage and local reliability (VLR) problems in MISO South.
The groups said the 90-day delay in releasing resource-specific data would protect competition and individual market participants.
FERC agreed with MISO that reporting on categories was not required by Order 844 for the resource-specific report.
SPP Order
The commission accepted part of SPP’s compliance filing but rejected other parts and directed it to make a further compliance filing within 30 days.
FERC found that the RTO’s proposed changes to its zonal uplift report partially complied with Order 844 requirements in that SPP would compile and post make-whole payments categorized by settlement area within 20 days of a month’s end. FERC also accepted a proposal to divide the report by settlement area, saying it “conforms to the commission’s definition of ‘transmission zone’ and provides an appropriate level of geographic granularity.”
But FERC said SPP’s filing didn’t specify what uplift categories it would report “and thus does not reflect all the uplift that SPP intends to report in compliance.” The commission said the proposed Tariff language indicated the report would be broken out by day, and it directed SPP to include the uplift types it will report and to note the report will be broken out by day in the compliance filing.
The commission said SPP’s proposed changes to the resource-specific uplift report also only partially complied with Order 844 because specific uplift categories would not be included in the report, leaving it incomplete. It directed the RTO to modify its Tariff changes to include resource-specific uplift categories.
While FERC agreed with many of the changes to SPP’s operator-initiated commitment report, it said the report did not meet requirements to include all commitments made for a reason other than to “minimize the total production cost of serving load.” The RTO contended that its reliability unit commitment processes minimize total production costs, but the commission disagreed, pointing to SPP Tariff and protocols that “make clear” that RUC processes minimizing total commitment costs are only a subset of total system production costs.
The commission directed SPP to revise its Tariff to include in the report commitments made under its day-ahead, short-term and intraday RUC processes. It found that SPP’s proposal to average the economic minimum across the commitment period does not comply with Order 844, saying the plan “provides less transparency into the size and timing of a system need.”
FERC also found that SPP’s Tariff revisions to TCPFs did not comply with requirements to enumerate any procedures by which factors may be temporarily changed. The commission said SPP conducts an annual review to consider changes to the factor values, but that the process does not address the “temporary, potentially intraday changes to those values.”
“Accordingly, we direct SPP to … clarify whether it temporarily changes its transmission constraint penalty factors,” the commission said, ordering SPP to revise the Tariff to include the procedures for temporarily changing those values and show its intention to provide notice to market participants as soon as practicable.
PJM Order
The commission approved PJM’s compliance filing with few substantive changes.
It rejected the Independent Market Monitor’s claim that PJM’s proposal to identify demand resources and economic load response participants by number, not name, did not comply with Order 844. The Monitor said the names of these resources are not confidential because they are publicly available through the Energy Information Administration and that demand resources should not be able to mask their identity when other participants are transparent.
The Advanced Energy Management Alliance countered that the Monitor’s recommendation would compromise competitive information, noting curtailment service providers’ investments in identifying and recruiting customers.
The commission ruled that PJM’s proposal to report the identification number of demand resources and their location “provides the same level of geographical granularity as there would be if PJM used specific resource names.”
The commission differed with the RTO’s interpretation that the definition of operator-initiated commitment is limited to new commitments that are brought online from an offline status.
FERC agreed that PJM does not need to report commitment extensions ordered to minimize total production costs during periods of price volatility. But it said “manual adjustments by PJM to increase or decrease the amount of committed capacity, or to extend the commitments of units that are currently running beyond the hour for which they were committed by PJM’s [security-constrained economic dispatch] software (i.e., a process to minimize total production costs), must be included in the operator-initiated commitment report, if those commitments are made for noneconomic reasons.”
The commission also rejected the Monitor’s request to require that PJM report the end time as well as the start time of operator-initiated commitments. It also rejected the Monitor’s request to require PJM to disclose operator-initiated commitments cleared before the day-ahead market closes, calling it “a collateral attack” on Order 844.
“In the Notice of Proposed Rulemaking, the commission considered including day-ahead must-run generation in the definition of operator-initiated commitments. However, after considering concerns that day-ahead must-run generation clears the day-ahead market on the basis of reliability and economics, the commission modified the definition to explicitly exclude these commitments,” FERC said. “The IMM did not seek rehearing on the definition of operator-initiated commitments.”
The Monitor also sought clarification that no rules prohibited it from reporting uplift data itself.
“While Order No. 844 does not apply to market monitors, we find that the IMM is not precluded from continuing to report uplift data … in the IMM’s State of the Market reports, to the extent this information does not violate the confidentiality provisions of the Tariff and Operating Agreement,” FERC said.
NEW ORLEANS — MISO’s Advisory Committee on Wednesday created a task team to continue exploring whether to extend a one-year “cooling-off” period to state regulators before they apply to serve on the RTO’s Board of Directors.
The new team will also examine other aspects of the board’s makeup and required qualifications, including whether the yearlong moratorium — currently applicable to industry participants appointed to the board — should be scrapped altogether.
Advisory Committee Chair Audrey Penner said the committee could recommend that the board amend its bylaws in MISO’s Transmission Owners Agreement to adopt any improvements identified by the team. FERC must ultimately approve any bylaws changes and neither MISO nor its board is under any obligation to act on Advisory Committee recommendations.
The committee has been discussing the issues since last fall, when Nancy Lange, then chair of the Minnesota Public Utilities Commission, was nominated to fill a seat on the board. RTO stakeholders ultimately elected Lange, though some said they would have been more comfortable if she had observed the one-year moratorium required of other company executives. At the time, some pointed out that Lange had been making decisions about the grid in a MISO state that overlapped with her board member training. (See Board Cooling-off Period Still Under Debate at MISO.)
“Welcome to our dysfunctional family,” Penner joked to Lange in opening the Wednesday meeting.
Lange now sits on the board’s System Planning Committee, which is charged with overseeing MISO’s annual transmission planning processes and spending.
“I’ve been on the other end of the MTEP [MISO Transmission Expansion Plan] in a way. I’ve seen the tussles … dreams that go into MTEP,” Lange said before a March 19 introductory presentation on the plan.
At the Wednesday meeting, Penner said there remains a “divergence of opinion” on whether the cooling-off period should apply to regulators. Some committee members have gone so far as to say the moratorium is no longer necessary.
Not all are sold on that idea.
“You could have a regulator denying a rate case on a Friday, and then deciding their transmission package on a Monday,” said Transmission Dependent Utilities sector representative Kevin Van Oirschot, of Consumers Energy.
But Wisconsin Public Service Commissioner Mike Huebsch said he stepped into that very situation as he switched from state representative to state regulator without a significant break in between roles. As a state representative, Huebsch said he argued passionately against the Badger Coulee high-voltage transmission line. By the time he was a Wisconsin regulator, he voted in favor of the line.
“It ended up going through my dad’s backyard, and I had to sign an affidavit saying I hadn’t talked to him about it over Thanksgiving,” Huebsch laughed, making the point that industry disagreements don’t have to follow individuals into new professional roles.
Huebsch said today’s transparency, especially in social media, means that the cooling-off period is an “archaic idea that’s no longer necessary.” He said any whiff of impropriety can now be widely shared on Twitter within minutes.
C-suite vs. Engineers
Some committee members also contend the board could benefit from more members with technical industry expertise. MISO bylaws currently dictate that six directors have corporate leadership experience in either board governance, finance, accounting, engineering or utility laws and regulation; another should have transmission system operation experience; another, transmission planning experience; and the final, experience in commercial markets and trading.
“You could fill this with six C-suite people and three engineers,” Huebsch observed.
Power Marketers sector representative Barry Trayers, of Sempra Energy Trading, said it seems that part of each quarterly in-person Advisory Committee meeting in front of the board is spent explaining MISO operations to new board members unfamiliar with the workings of the RTO.
Penner also said she’s heard concerns that only two stakeholders are permitted on MISO’s Nominating Committee, which vets and selects board candidates for stakeholder voting. The group is currently composed of two stakeholder seats and three director seats.
Missouri Public Service Commissioner Daniel Hall, who served on last year’s Nominating Committee, said he would have found value in “at least one more” Advisory Committee member contributing to the group’s decisions.
Independent Power Producers sector representative Mark Volpe, of the Coalition of Midwest Power Producers, said the Nominating Committee is an anomaly among entities with boards of directors because directors outnumber stakeholders and could in theory decide a candidate’s fate by themselves.
The Advisory Committee does not yet have volunteers to serve on the board process task team. Although task team membership would be voluntary, Penner said she would likely limit sectors to one representative apiece.
Meanwhile, the Advisory Committee appointed Minnesota Public Utilities Commissioner Matt Schuerger and Transmission Owners sector representative Jeff Dodd, Ameren’s director of transmission policy, to sit on this year’s Nominating Committee.
A California State Senate hearing illustrated the rift over community choice aggregators, with some lawmakers warning of blackouts and one lashing the top state regulator for his alleged “hostility” toward the groups.
Scott Wiener | California State Senate
“Frankly, with all respect, Mr. Picker, your comments here today further bolster my belief that I don’t want to see the CPUC having a greater role [regulating CCAs],” Sen. Scott Wiener told Public Utilities Commission President Michael Picker at the March 19 hearing of the Energy, Utilities and Communications Committee. “I think the CPUC would pretty quickly move to kill off CCAs. I’m just being super blunt.”
Wiener said he thought the PUC was attempting to “double down on this hyper-centralized model that has not worked well for California” and had displayed hostility toward CCAs and distributed energy resources such as solar power.
The San Francisco Democrat next took aim at Picker’s testimony in a recent State Assembly hearing, where he said the commission had received 11 resource adequacy (RA) waiver requests last year from CCAs and electricity service providers (ESPs), when in fact 10 of the waivers were from ESPs, which provide electricity directly to commercial and industrial customers, and another was from one of the state’s large investor-owned utilities. (See Calif. CCAs, Decarbonization Provide Reliability Challenges.)
Picker responded during the testy exchange with Wiener by saying, “I will apologize for the way I characterized the problem, but I will not say there’s not a problem.”
During his Senate testimony, and in his earlier Assembly testimony, Picker expressed concern that CCAs may be unable to meet the state’s local RA requirements. Some serve areas with limited transmission capacity to import electricity, he said, and might not be able to compete for electricity from generators within their load pockets during times of high demand.
Michael Picker | California State Senate
Picker said it may be necessary to designate an entity to serve as a central buyer of electricity to backstop CCAs and other load-serving entities. That entity could be an IOU, such as Southern California Edison, or an independent agency created by lawmakers. A bill, AB 56, to establish a central procurement entity was introduced in December.
Picker’s sentiments were echoed by several lawmakers who expressed concerns about a repeat of the state’s 2000/01 energy crisis, when rolling blackouts afflicted California.
Sen. Robert Hertzberg (D) this year introduced a bill, SB 520, that would authorize the PUC to develop threshold attributes for an LSE to serve as a provider of last resort if other LSEs fail to deliver electricity to retail customers. It would also instruct the commission to develop a method, such as an auction, for selecting the provider of last resort and to determine how that entity would benefit from its role.
“If the perfect storm happens, there has to be a backup plan,” Hertzberg told the committee.
The state’s IOUs are currently the de facto providers of last resort, but as customers migrate away from IOUs and the utilities become poles-and-wires companies, they may be unable to fulfill that function, he said.
Robert Hertzberg | California State Senate
Hertzberg, a veteran state lawmaker who served as Assembly speaker during the energy crisis, said lawmakers created CCAs in the early 2000s as an interim step to deliver renewable energy to local communities.
The state’s first, Marin Clean Energy, launched in 2010. There are now 19 CCAs, primarily in wealthy coastal California, with a dozen more under consideration by city and county governments statewide. CCAs are expected to serve more than 10 million customers, or about a quarter of California’s population, this year, according to the California Community Choice Association.
Hertzberg said the shift away from IOUs, the proliferation of renewable energy and other seismic shifts represent a “new world order” in terms of electricity delivery and reliability that still must be sorted out by policymakers.
“They’ll continue to survive,” Hertzberg said of CCAs, “but I think we’re all in for a significant change to make sure we have reliability for the people of California.”
FERC on Tuesday approved Tariff revisions intended to relieve costs for MISO resources pseudo-tying into PJM despite criticism the changes don’t go far enough in easing their financial burdens (ER19-34).
The new MISO Tariff provisions are the second phase of a joint MISO-PJM effort to facilitate the flow of pseudo-tie transactions between the RTOs by relieving redundant congestion costs. The need for the rule changes arose as a growing number of MISO generators sought to meet PJM’s requirement that external resources establish a pseudo-tie to participate in its capacity market.
Last July, FERC approved amendments to the MISO-PJM Joint Operating Agreement that eliminated most overlapping congestion charges applied to pseudo-tie transactions by improving alignment of the RTOs’ market-to-market settlement procedures and increasing day-ahead coordination (ER18-136-003, ER18-137-003). The commission also approved PJM’s Phase 2 revisions, which modified its Tariff to provide rebates for deviations from day-ahead commitments and removed the remaining overlapping congestion charges not addressed by Phase 1 (ER18-1730). (See FERC OKs MISO-PJM Double Charge Fix for Pseudo-ties.)
MISO’s Phase 2 revisions update the RTO’s Tariff to include pseudo-tie transactions in “the types of interchange schedules that a market participant must report on and coordinate with the transmission provider.” They also add “language that allows pseudo-tie transactions to utilize day-ahead virtual transactions to align the transmission usage charges and available congestion hedges” — that is, financial transmission rights. MISO said the revisions clarify that participants with pseudo-tied resources can use the day-ahead market to hedge against real-time congestion.
Another provision ensures that pseudo-tied resources out of MISO are charged for administrative costs in the same manner that market participants with physical transactions are charged by altering the billing formula underpinning those costs.
In approving the Tariff revisions, the commission noted Tilton Energy and other stakeholders have argued that MISO’s assessment of any administrative fees for pseudo-tie transactions violates the RTO’s Tariff, an issue being contested in other FERC proceedings (EL16-108; EL17-29 and EL17-54 against MISO; and EL17-31 and EL17-37 against PJM).
“Our finding here is that the reduction of the administrative charges is just and reasonable, and the question of whether MISO is authorized under its Tariff to assess these administrative charges will be addressed in the orders on the MISO/PJM pseudo-tie congestion complaints against MISO,” the commission wrote.
The commission said those proceedings also were the appropriate venue for addressing American Municipal Power and Dynegy’s objection to MISO’s continued practice of subjecting pseudo-tied resources to transmission usage charges.
“Whether the commission ultimately determines that the MISO’s assessment of transmission usage charges on pseudo-tied resources is unauthorized under the MISO Tariff does not affect the currently existing right of market participants with pseudo-tie transactions to use virtual transactions,” the commission said.
FERC also rebuffed Tilton and AMP’s contention that MISO should implement a rebate mechanism similar to that of PJM in order to ensure all overlapping congestion charges are eliminated.
“Based on PJM’s and MISO’s representations in their Phase 1 revisions and Phase 2 revisions proceedings, and the absence of evidence to the contrary, the RTOs have demonstrated that the congestion overlap has been eliminated,” FERC found.
The commission did direct MISO to amend its proposed revisions to clarify that pseudo-tie transactions are not technically included in interchange schedules, despite using language indicating they should be treated as such with respect to coordination with MISO.
FERC on Tuesday rejected MISO’s proposal to impose more stringent site control requirements and increase the milestone payments for interconnection customers, while saying it could also be persuaded to accept the plan with certain revisions.
The commission found MISO didn’t adequately demonstrate its proposals were reasonable and not unduly discriminatory, even though it agreed more stringent site control requirements and higher milestones could help reduce speculative and duplicative projects. Still, the commissioners did offer guidance on how a reworked proposal might gain approval (ER19-637).
“We recognize that the filing represents a significant undertaking by MISO and its stakeholders to accomplish the important objective of preventing a large volume of speculative, non-ready projects from entering [phase one of the definitive planning phase] and subsequently withdrawing from the queue, creating adverse effects for other interconnection customers,” the commission said.
MISO transmission | MISO
MISO had proposed interconnection customers follow one of two courses. They could either demonstrate 100% site control 90 days prior to the start of entering the definitive planning phase (DPP) of the interconnection queue or provide supporting documents and a $10,000/MW cash deposit (capped between $500,000 and $2 million) only if “regulatory limitations prohibit the procurement of site control.” (See MISO to File Queue Changes Before Year-end.) The DPP is the last three-part stage of studies, cost impacts and assessments that generation projects must scale before being granted interconnection.
MISO currently requires interconnection customers to either demonstrate 75% site control or provide a $100,000 cash deposit in lieu of demonstrating site control at the time of queue application. RTO staff have long characterized the requirements as too lax to deter non-ready projects, instead using the early DPP to “test multiple interconnection project concepts.”
MISO also proposed to change the first milestone payment from a $4,000/MW fee to 10% of the average network upgrade cost from the last three DPP cycles. MISO said the averages would be footprint-wide.
The RTO has said the proposal would speed up the queue by encouraging stalled projects to withdraw earlier in the process. The queue currently takes a little more than 500 days to complete, which MISO says is due to a “marked increase in the number and volume of interconnection requests … over the past two years.”
The Shortcomings
FERC said MISO’s proposed language that project owners demonstrate “exclusive use” site control conflicts with a Tariff section that allows interconnection customers to submit “multiple interconnection requests for a single site” and a policy that requires customers to submit separate requests for generating units that use multiple fuel sources. FERC pointed out the two-application policy applies to co-located generating facilities paired with a storage device.
“We find it unclear from MISO’s filing how interconnection customers would be able to meet MISO’s ‘exclusive use’ standard for such a generating facility. … It appears that these provisions are in conflict,” FERC said, suggesting MISO clear up how it interprets exclusive use site control for facilities that operate with multiple primary fuel sources.
FERC also said MISO didn’t describe what it expects from third-party analysis provided by an interconnection customer that wants to secure less land than MISO requires. The RTO’s acres-per-megawatt requirement differs based on fuel type, and it proposed that deviations from the land limits would have to be supported with a third-party analysis.
The commission also said MISO did not justify “the variable nature and calculation” of its proposed milestone payment on several fronts. It said the inconsistent payment average diminishes accounting certainty for interconnection customers, unfairly burdens projects in sub-regions where network upgrade costs are traditionally lower, ignores the fact that upgrade costs can vary widely across each study cycle and unfairly relies on using the costs of only preliminary network upgrades “that may not actually be built.”
Finally, the commission said MISO’s plan to shorten the window for withdrawing projects to get full refunds on the two subsequent milestone payments wasn’t appropriate when considering its proposed increase to the first milestone payment. FERC also said MISO didn’t consider that its recent removal of the first affected system analysis in the first phase of the DPP keeps interconnection customers in the dark a little longer on network upgrade costs. (See MISO Plan to Reduce Queue Studies Gets FERC Nod.)
“MISO’s proposal would require interconnection customers to post at-risk milestone payments without knowledge of potential affected system impacts that may alter their network upgrade cost estimates,” FERC said.
FERC added it might find a shortened refund window reasonable “under the appropriate circumstances.”
MISO’s queue proposal is linked with another, newer proposal to further accelerate the DPP by cutting the respective number of days throughout the three phases. (See “Measures to Accelerate Existing DPP” in MISO Details Fast-track Queue Options.) MISO staff this month had said they were relying on the increasing site control deposits and milestone fees to make for less complicated DPP modeling due to fewer late project dropouts, thus cutting the number of days other projects spend in the queue.
