FERC on Thursday rejected a request by developers of a proposed $2 billion pumped storage project for a declaratory order entitling it to cost-based rate recovery as a transmission asset in CAISO.
The commission sided with CAISO and the California Public Utilities Commission, which had argued that Nevada Hydro’s petition for its Lake Elsinore Advanced Pumped Storage (LEAPS) project was an end run around the ISO’s transmission planning process (TPP) (EL18-131).
Lake Elsinore | City of Lake Elsinore
“We dismiss Nevada Hydro’s petition and find that a request to designate LEAPS as a transmission facility is premature at this time,” FERC wrote. “LEAPS has not been studied in the CAISO TPP to determine whether it addresses a transmission need identified through that process, and, if such a need were met, how the facility would be operated. Absent such information, the commission cannot make a reasoned decision on whether LEAPS is a transmission project and thus eligible for cost recovery under the [transmission access charge].”
CAISO said FERC should not accept Nevada Hydro’s analysis that LEAPS is a cost-effective solution to transmission planning needs, noting that the company’s benefits study relied heavily on revenues from market-based services such as energy market sales, regulation, load following, capacity, spinning and ramping. The CPUC said it is unlikely that pumped storage will be the most cost-efficient means of meeting reliability, grid integration or greenhouse gas reduction targets between now and 2030.
The $2 billion LEAPS project, which entered CAISO’s interconnection queue in 2005, has had a long and controversial history, with local governments and many residents opposed to its construction on the natural 3,000-acre Lake Elsinore, adjacent to the Cleveland National Forest in Southern California’s Riverside County.
This is the second time Nevada Hydro has failed to obtain FERC approval to advance the project. In the 2008 Nevada Hydro case, the commission rejected a request that CAISO assume operational control over the facility and found that the developers failed to show why it should be treated differently from other pumped hydro facilities that had not been granted rolled-in transmission pricing.
In seeking the declaratory order, Nevada Hydro said it, not CAISO, would maintain operational responsibility for LEAPS.
But the commission said that change did not entitle the project to circumvent the ISO’s planning process.
“Requiring LEAPS to be reviewed through the CAISO TPP is consistent with the commission’s policy that regional transmission planning processes should identify transmission needs and solutions in a coordinated, nondiscriminatory process that is open to all interested stakeholders,” the commission said. “We note that CAISO has committed to studying LEAPS as a transmission proposal, both as a means to address reliability needs (if it is submitted in an appropriate request window of CAISO’s TPP and if the proposal specifies the CAISO-identified reliability constraints the project could mitigate), and as an economic planning study request.”
The project would include 500-MW of pumped storage, the Talega-Escondido/Valley-Serrano 500-kV Interconnect and a 30-mile line to transmission systems owned by Southern California Edison and San Diego Gas & Electric. Its hydroelectric license application is pending before FERC (P-14227-003).
FERC on Thursday affirmed an administrative law judge’s decision to assign a Minnesota city’s portion of the 345-kV Hampton-North Rochester line (H-NR) to Northern States Power’s pricing zone, rejecting arguments by NSP parent Xcel Energy (ER14-2154-006, ER15-277-005).
The H-NR line was completed in September 2016 as part of the Hampton-Rochester-La Crosse (HRL) transmission project into Wisconsin. The city of Rochester, Minn., through its Rochester Public Utilities (RPU) municipal utility, owns 14.7% of the line; NSP, Southern Minnesota Municipal Power Agency (SMMPA) and Dairyland Power Cooperative are co-owners, at 49.5%, 23.4% and 12.4%, respectively.
The line was included in MISO’s 2008 Transmission Expansion Plan, and the RTO asked FERC in 2014 to add RPU as a transmission owner in NSP’s zone, where the line is located, enabling the city to receive its annual transmission revenue requirement (ATRR) for the line from the zone.
MISO’s Tariff specifies that within each zone, transmission rates are based on the sum of the revenue requirements for facilities “located within that pricing zone.” Xcel argued that the language did not refer to the facilities’ physical locations, but rather the zones the facilities’ ATRRs are “allocated” to for ratemaking purposes. The company pointed out that the word “physically” does not precede the word “located” in the language. Thus, Xcel argued, the Tariff does not mandate that H-NR should allocated to NSP’s zone.
In his initial decision in May 2017, ALJ David H. Coffman found this unpersuasive, pointing to the dictionary definition of “located.”
“The plain meanings of the terms ‘located’ and ‘allocated’ are not remotely similar,” he wrote.
Xcel took exception to the ALJ using dictionary definitions to support his conclusions. But the commission said Coffman was merely using them as evidence of common sense interpretation of the words.
“We are unpersuaded by arguments seeking to differentiate the use of the word ‘located’ in different contexts with respect to the interpretation of” the Tariff, FERC said. “Such arguments stray from the ordinary meaning of the word and also introduce additional problems, notably different interpretations of the word ‘zones’ with respect to the location of load and the location of transmission facilities. …
“Transmission facilities are not ethereal concepts but fixtures that cannot be moved from zone to zone,” FERC added. “Accordingly, given this context, interpreting the word ‘located’ as ‘existing in a particular place’ is logical.”
Xcel also argued that because Dairyland was allowed to allocate its ATRR for both H-NR and HRL to its own zone, where its load is located, RPU’s ATRR need not be allocated to NSP’s zone. Rather, it could have been allocated to SMMPA’s zone, where RPU’s transmission facilities and load are located.
The ALJ, however, noted that the MISO Tariff allows an exception if the TOs agree upon a different allocation and FERC approves the agreement, as occurred in February 2017 for HRL. (See FERC OKs Settlement, Opens Docket in Dispute over Minn.-Wis. Tx. Project.) That agreement excluded the ATRR allocation for H-NR, which could not be resolved at the time.
JPZ Agreement Dispute
In a related order, FERC ended its examination of the joint pricing zone (JPZ) agreement among TOs in NSP’s zone, after NSP added RPU as a party to the agreement pending the resolution of the ATRR dispute (EL17-44). NSP had balked at adding RPU even after FERC approved it as a MISO TO. The commission had warned in February 2017, when it began its investigation, that revisions to the MISO Tariff or Transmission Owners Agreement (TOA) could be necessary to prevent such exclusions in the future.
Under the TOA, MISO distributes revenue to each JPZ’s host TO, which then distributes it among each TO in its zone. The RTO had been distributing revenue to NSP based on RPU’s approval as a TO in the zone, but because NSP had not added RPU to the agreement, the company was withholding the city’s revenue.
While RPU acknowledged that its situation had been resolved, it told FERC that the TOA gives host TOs “the opportunity to leverage the need for a JPZ agreement against a new, typically smaller, transmission owner seeking to recover some or all of its transmission revenue requirement from that zone.”
“This leverage is often coupled with claims of undue cost shifts and various allegations of unjust and unreasonable rate impacts or cost allocations to make it difficult for a smaller transmission owner such as RPU to integrate into MISO,” RPU said.
FERC disagreed. “There is neither evidence that such denial, or use of that threat to affect the terms of cost allocation, is widespread, nor evidence that the host transmission owner responsibilities have either precluded new transmission owners from receiving their respective ATRRs that have been accepted by the commission or would have a chilling effect on new transmission owners’ interest in joining MISO, as RPU suggests.”
The commission, however, reiterated that “a JPZ agreement should reflect commission-accepted transmission rates. … Therefore, any dispute associated with a new transmission owner’s ATRR should not delay the filing of a JPZ agreement to include a new transmission owner to the zone.”
Chairman Kevin McIntyre recused himself from both orders.
FERC last week approved CAISO’s plan to reduce the capacity available in its congestion revenue rights auctions but rejected a proposal to cut CRR payments that had garnered opposition.
The commission approved CAISO’s proposal to reduce transmission system capacity available in the annual CRR allocation and auction processes from 75% to 65%, which was unopposed. But FERC rejected as unjust and unreasonable a plan to eliminate full funding of CRRs and instead scale payouts to align with revenue collected through the day-ahead market and congestion charges (ER18-2034).
The rejection means CAISO may have to seek additional changes to fix a system it says unfairly charges ratepayers around $100 million annually, largely to fund speculators’ profits.
Ratepayer auction revenues compared with congestion payments for auctioned CRRs | CAISO Department of Market Monitoring
CRRs are financial instruments that can be used as a hedge against congestion charges or as an investment to speculate that the congestion rent will be greater than the purchase price. Shortfalls between CRR revenues and payouts resulted in ratepayers making up a difference of approximately $500 million over five years, the ISO has argued.
Under the scaling plan, CAISO would have compared the congestion revenue and revenue from counterflow CRR holders for each constraint to the payments due to prevailing flow CRR holders for that constraint. When it did not collect enough revenue to pay prevailing flow CRRs the full value for an hour, the ISO would reduce the payments proportionally.
CAISO proposed scaling CRR payments only in the prevailing flow direction, not payments due from counterflow CRR holders on the same constraint. Because counterflow CRRs fund prevailing flow CRRs, CAISO said discounting counterflow CRRs could increase revenue insufficiency.
The scaling plan was opposed by Calpine, the Western Power Trading Forum, the Alliance for Retail Energy Markets and others.
“As protesters note, the commission has long held that counterflow and prevailing flow CRRs should be netted against one another such that the expected net value of two obligation CRRs of equal megawatts from A to B and B to A will be equal to zero,” FERC wrote, citing its 2006 ruling on CAISO’s Market Redesign and Technology Upgrade (MRTU) and a 2016 order on PJM’s financial transmission rights market. (See FERC Finds PJM ARR/FTR Market Design Flawed; Rejects Proposed Fix.)
“Consistent with the commission’s findings in the MRTU and 2016 PJM FTR orders, we continue to believe that a symmetric approach is just and reasonable, while an asymmetric approach has not been shown to be just and reasonable.”
The commission added that CAISO’s proposal would have the “undesirable” effect of making the CRR product less transparent.
“Market participants could face difficulties valuing a counterflow hedge relative to a prevailing flow hedge, since one would be discounted while the other would not,” the commission said. “This lack of transparency could discourage market participants from bidding for counterflow CRRs, which could reduce liquidity and could, in turn, exacerbate the CAISO CRR market’s current market efficiency problems,” such as the auction revenue shortfalls.
The capacity release reduction proposal will cut the amount of CRRs made available in the annual auction while increasing those available through the monthly auction. In approving the plan, the commission noted that it “shifts the release of CRR capacity from the annual auction to the monthly auction, where CAISO has more information concerning the topology of the transmission system. CAISO’s analysis shows that a 10% decrease in available annual capacity would decrease the amount of CRRs that are likely to be infeasible in the day-ahead market and reduce CRR revenue insufficiencies.”
The issue has pitted the ISO’s Department of Market Monitoring against financial traders, which the department says were the biggest beneficiaries of the current market design.
In the first half of 2016, the Monitor said, financial traders made $22.7 million in profits, more than doubling their investments as they paid 49 cents into the ISO’s auctions for every dollar earned. Over the same period, power marketers and generators took in about $3.9 million and $800,000, respectively, paying 82 and 85 cents for every dollar of congestion revenue earned. (See CAISO Monitor Seeks Congestion Rights Revenue Auction Reform.)
Thursday’s order was the second time this year that FERC has addressed CAISO’s attempts to upgrade its CRR auctions.
In June, FERC approved a separate set of CRR rule changes, including limiting allowable source-and-sink pairs for CRR transactions to those that align with typical supply delivery paths. (See FERC OKs Tighter Rules for CAISO CRR Auction.)
Transactions using non-delivery sources and sinks, such as between two generator locations, represent about 81% of auction shortfalls, the ISO noted in arguing for the change.
FERC can’t overturn the New England Power Pool’s longstanding ban on public and press access to stakeholder meetings, NEPOOL told the commission Thursday.
In a motion to dismissRTO Insider’s protest seeking to open meetings to the public and press, NEPOOL said FERC lacks jurisdiction to force changes and that RTO Insider lacks standing to challenge the rules.
“NEPOOL does not engage in the transmission or sale of electric energy in interstate commerce, nor does it operate any facilities that are used for such purposes,” it said. “As such, NEPOOL is not a ‘public utility,’ and its supposed ‘press ban’ is not a ‘rate, charge or classification’ related to the transmission or sale of energy. These provisions of the [Federal Power Act] do not provide any basis for RTO Insider’s complaint.”
On Aug. 13, NEPOOL asked FERC to approve amendments to its Agreement to codify an unwritten policy of banning news reporters and the public from attending the group’s stakeholder meetings (ER18-2208). The group drafted the revisions after RTO Insider reporter Michael Kuser applied for membership in NEPOOL’s Participants Committee as an End User customer in March.
DayPitney attorneys David Doot and Patrick M. Gerity authored NEPOOL’s defense of its rules barring the public and press from attending stakeholder meetings. | Day Pitney
RTO Insider responded to NEPOOL’s filing with a Section 206 complaint Aug. 31 asking the commission to overturn the organization’s ban or terminate the group’s role and direct ISO-NE to adopt an open stakeholder process like those used by other RTOs (EL18-196). New England is the only one of the seven U.S. regions served by RTOs or ISOs where the press and public are prohibited from attending stakeholder meetings.
NEPOOL’s 57-page filing, which it submitted in both dockets, cites the D.C. Circuit Court of Appeals’ 2004 order rejecting FERC’s attempt to force CAISO to replace its governing board. The D.C. Circuit vacated FERC’s action and remanded the case, ruling that “FERC … does not have the authority to reform and regulate the governing body of a public utility under the theory that corporate governance constitutes a ‘practice’ for ratemaking authority purposes.”
NEPOOL also said RTO Insider’s request that FERC open the organization’s meetings or strip it of its FERC-authorized role as ISO-NE’s stakeholder body is a “collateral attack” on prior commission orders giving NEPOOL its role in the RTO. While NEPOOL claimed FERC had no jurisdiction to force it to change its rules, it did not challenge the commission’s authority to order ISO-NE, which it noted “is the FERC-jurisdictional public utility,” to adopt a new stakeholder body.
Former FERC Chairman Pat Wood III and former Commissioner Nora Mead Brownell have said they were unaware when they approved NEPOOL as ISO-NE’s stakeholder body in 2004 that NEPOOL barred the public and press from its meetings. According to former Chairman Jon Wellinghoff, FERC commissioners also were unaware of the ban in 2008 when they approved Order 719, which requires that RTO/ISO processes be inclusive, responsive and represent minority interests. (See Wood, Brownell: Unaware of Press Ban When OK’d NEPOOL.)
Seven Intervenors File Comments
NEPOOL was among seven intervenors filing comments in the docket opened by RTO Insider. All but one of the others — including consumer, environmental and press freedom advocates — joined in calling for the opening of the meetings.
Also calling on the commission to open the meetings were a dozen members of the House of Representatives. Their Sept. 18 letter said NEPOOL’s proposal to codify its unwritten ban on public and press coverage “at best … is misguided; at worst it is an unconscionable restraint on the critical need for transparency in the New England energy and electric markets. … Codifying such a ban is antithetical to principles of good governance and the mission of FERC.
“The current NEPOOL practice of publicly releasing meeting agendas, draft resolutions and background materials prior to meetings, as well as official records and meeting minutes following meetings, is not an adequate substitute for attending and understanding the meeting itself,” they continued. “Planning for the electric grid is an inherently governmental function and justifiably must be transparent to the greatest extent possible.”
The letter was signed by Rep. Frank Pallone (D-N.J.), the ranking member of the House Energy and Commerce Committee; Rep. Fred Upton (R-Mich.), the chairman of the committee’s Subcommittee on Energy; Rep. Bobby Rush (D-Ill.), the ranking member on the subcommittee; seven of nine members from Massachusetts’ delegation; and one representative each from Rhode Island and Vermont.
In their filings, NEPOOL member William P. Short III and the Reporters Committee for Freedom of the Press essentially repeated arguments they made opposing the ban in NEPOOL’s docket. (See NEPOOL Alone in Support for Press, Public Ban.)
‘Not Informal Brainstorming Sessions’
But the New Hampshire Consumer Advocate, Public Citizen and a joint submission by environmental groups Earthjustice, the Conservation Law Foundation and the Sustainable FERC Project expanded on their earlier filings.
The environmental groups noted that FERC previously ordered modifications to the NEPOOL Agreement in a 1997 order directing the organization to eliminate a requirement that members “‘be engaged in or propose to engage in the wholesale or retail electric business in New England,’ noting that it had prohibited geographic limitations on membership in power pools in a prior order.”
D. Maurice Kreis | D. Maurice Kreis
New Hampshire Consumer Advocate D. Maurice Kreis said that NEPOOL’s “jump ball” rights to submit filings opposing ISO-NE makes it more powerful than other RTO stakeholder bodies. “In legal terms … NEPOOL is as powerful as ISO New England is with respect to the market rules that govern how electricity and related products are traded,” he said.
The jump-ball provisions “belie the impression NEPOOL seeks to convey here of serving merely as a kind of debating forum whose decisions rise and fall purely based on their persuasive value,” he added. “Meetings of the principal committees of NEPOOL are not informal brainstorming sessions.
“There are also potential First Amendment implications of a commission-approved restriction on the speech and publication activities of NEPOOL meeting attendees. While NEPOOL is not itself an instrumentality of government, ‘private speech prohibitions can still implicate the First Amendment when given the imprimatur of state protection through civil or criminal law,’” he said, citing the Supreme Court’s landmark 1964 ruling New York Times Co. v. Sullivan.
Tyson Slocum, energy program director for Public Citizen, challenged NEPOOL’s contention that an “overwhelming majority” of NEPOOL participants voted to ban journalists. Of the 113 NEPOOL participants who were eligible to vote during the June 26 NEPOOL meeting to consider banning reporters, “more voted to abstain (58) than the number casting votes for (32) and against (23) COMBINED.”
Slocum said some current and former NEPOOL officers that supported the ban “earn outside income selling ‘intelligence’ about NEPOOL proceedings, creating financial conflicts of interest.”
“Twenty of the 32 votes in favor [of the ban] were represented by lobbyists who either serve as NEPOOL officers or were recruited by NEPOOL to serve as an expert witness on behalf of NEPOOL’s advocacy to ban journalists. This is an alarming concentration of voting power by lobbyists who have a financial self-interest to maintain a ban on the public and journalists. … NEPOOL’s restrictions on public and media access allow those with restricted access to possess valuable information about NEPOOL activities that are nonpublic, which they can then sell for lucrative amounts to interested parties.”
Slocum noted that almost 80% of NEPOOL’s 2018 budget is generated through membership fees and expenses and that NEPOOL members in the Transmission and Publicly Owned sectors can collect these expenses from ratepayers. “While NEPOOL likes to characterize itself as a ‘private, voluntary association,’ its reliance on ratepayer money — when combined with FERC-delegated authorities — mean NEPOOL is not entitled to be treated as a normal ‘private’ association for purposes of admitting the general public and journalists into its policy-related meetings.”
Consultant Challenges ‘Mischaracterization’
Aside from NEPOOL, the only filing that did not support opening the meetings was one by consultant Erik Abend, who said he was seeking to correct the “mischaracterization” of his business in RTO Insider’s complaint.
Abend, the primary NEPOOL committee member for the Small Renewable Generation Group in the Alternative Resources Sector, acknowledged that he provides “high-level explanations, analysis and advice” on issues discussed at stakeholder meetings, both to his clients and to non-NEPOOL members through a weekly summary published to a secure website for the Northeast Energy and Commerce Association (NECA).
Abend said his role does not meet NEPOOL’s proposed definition of “press” and that his summaries “do not directly quote or paraphrase any statements made by market participants during any of the NEPOOL committee meetings. … As with the summaries that I provide directly to my NEPOOL member clients, the information contained in these summaries for NECA are drawn directly from materials that are publicly available from the ISO-NE and NEPOOL websites.”
Meetings are ‘Not Secret’
In its filing, NEPOOL said it was entitled to “discriminate” in allowing consultants to attend meetings while barring the press because the former “do not endanger the tradition of open dialogue in NEPOOL meetings by publicly reporting on the statements of other members.”
NEPOOL said RTO Insider lacks standing to challenge its rules because it does not participate in New England “either as a market participant or an end-use customer.” It also said the company could not contest the organization’s refusal to admit its reporter, Michael Kuser, a Vermont resident.
It insisted its meetings are “far from secret. The date, time and location of NEPOOL meetings are posted publicly and are available online … [and] the agendas and materials for each meeting are almost all circulated well in advance.”
It noted that its participants include consumer-owned utility systems, public interest groups, state consumer advocates and representatives of end-use consumers, and that state regulators and elected officials can attend in person or through delegates.
The group said it balances “two types of ‘transparency’ – (i) transparency to the non-stakeholder general public; and (ii) transparency among its meeting attendees.”
ST. PAUL, Minn. — Having fulfilled its original mandate, MISO’s Energy Storage Task Force (ESTF) will get a new lease on life: as an expert advisory panel on increasingly sophisticated storage issues.
The move means the task force will begin developing white papers on technical storage issues and approaching other stakeholder committees about recommended agenda items.
MISO’s Steering Committee last week endorsed the change to help resolve an identity crisis that arose this spring after the task force wrapped up its key mission of identifying discussion topics on FERC Order 841 compliance to be assigned to larger stakeholder committees.
The committee approved a revised ESTF charter last month that allows the group to evaluate energy storage issues rather than simply identifying them for committee assignment. It can also make recommendations directly to MISO and stakeholders, without first approaching the committee. (See MISO Grants Storage Task Force More Authority.)
But stakeholders and ESTF members began asking if the task force should stop reporting directly to the Steering Committee and perhaps report to another committee actively discussing electric storage. Under MISO’s Stakeholder Governance Guide, the Steering Committee is tasked with assigning new grid issues to stakeholder committees.
Although the ESTF will not change its reporting relationship, the changes mean ESTF leadership can now reach out to larger stakeholder entities like the Resources Adequacy Subcommittee and the Market Subcommittee to discuss possible storage agenda items and updates ahead of meetings, as suggested by Xcel Energy’s Carolyn Wetterlin during a Sept. 19 Steering Committee meeting.
Wetterlin pointed out that many storage issues naturally overlap stakeholder committees despite MISO’s redesign that discourages duplicate discussions among committees.
The ESTF, at the Steering Committee’s direction, will also explore the possibility of creating white papers on technical storage issues that went largely undiscussed while the group dealt with Order 841.
Committee Chair Tia Elliott said after FERC first issued the order, MISO was working quickly to identify various storage issues and place them into the most appropriate stakeholder committee. She said that immediate need may have overshadowed the potential for the ESTF to discuss storage participation models and innovation beyond Order 841. She suggested the ESTF could now take on those periphery issues and work with MISO to create white papers.
“I want to make sure that stakeholders are not being stymied by the process, and bureaucracy is not holding up the ESTF’s work. I’ve heard offline discussion that red tape is getting in the way, and that was never the intent of the stakeholder redesign,” Steering Committee Vice Chair Audrey Penner said.
Entergy’s Yarrow Etheredge said white papers would be helpful to explore technical details, such as how exactly storage can function as transmission. “I think there’s a role for the storage task force there, but unfortunately, they’d have to discuss issues already assigned to another committee,” she said.
Northern Indiana Public Service Co.’s Bill SeDoris said it would be helpful if the task force wasn’t required to go before the Steering Committee every time it wants to raise a possible issue for another stakeholder committee to discuss.
Elliott said the committee will examine whether the practice of obtaining its approval before moving issues to other committees is working as intended. In the meantime, she urged ESTF Chair John Fernandes to come forward with storage issue assignments as needed and said the committee could hold special conference calls to assign new issues.
Fernandes said he didn’t mind if the task force continued to report to the Steering Committee; however, he said bureaucratic limitations should not stifle discussion in committee meetings.
“Even as a storage guy, I wouldn’t predict what’s going to happen with storage two years out. It’s moving that quickly. … Flexibility is key,” Fernandes said. “I think everybody appreciates that this is a little tricky right now.”
Fernandes said the ESTF’s next meeting will tackle ideas on how storage will be charged for transmission reservations and discuss how hybrid storage setups might interact with the MISO system.
ST. PAUL, Minn. — MISO’s Advisory Committee appeared split last week over whether the RTO should assume greater authority in granting planned outages, with many members offering alternative and complementary ideas to increased outage control.
Following a tradition established three years ago, the Sept. 19 Advisory Committee “hot topic” discussion began with a theme song.
“We have a generally aging generation fleet, and that’s increasing outages and worsening coordination of those outages,” Rauch said.
According to its Business Practices Manual, MISO can only “recommend [an outage] schedule that maintains system security and minimizes adverse impacts.” But in its 2016 State of the Market report, the Independent Market Monitor raised the need for MISO to have a bigger say in outage scheduling, kicking off an off-and-on discussion ever since. (See “Generation Outages,” MISO in Harmony with IMM State of the Market Report.)
Discussion moderator Julia Johnson, president of regulatory advising firm Net Communications, took a more optimistic approach, playing “The Power” by Snap!
“We’ve got to figure out who is ‘the lyrical Jesse James,’” Johnson said, urging stakeholders to offer their best ideas to minimize outage impacts.
Some Advisory Committee members said the situation has become such that MISO members cannot effectively coordinate outages to avoid emergency conditions.
But Minnesota Public Utilities Commissioner Matt Schuerger said the Organization of MISO States does not support giving MISO expanded authority in approving outages, with the group saying that the RTO should “articulate a compelling need before any new authority is considered.” OMS maintains that MISO already is allowed to analyze generator outage requests and recommend outage scheduling changes as needed.
Kevin Murray, representing the Coalition of Midwest Transmission Customers and MISO’s Eligible End-User Customers sector, said he understood regulators’ hesitancy to “turn over the keys to the car.” But he said in his 27 years in the business, he had never seen MISO call a NERC Level 2 emergency like the one seen during the previous week. (See MISO in Conservative Ops After Emergency Declaration.)
“We shouldn’t be having these events on a Saturday. We need to do some soul searching,” Murray said. He also pointed to FERC and NERC’s recently announced inquiry into the January cold snap that resulted in generation outages and loads that approached summertime levels in MISO South. (See FERC, NERC to Probe January Outages in MISO South.)
“The writing is on the wall. … Either we do something, or they do something,” he said.
Several stakeholders said MISO should act to better coordinate outages before winter arrives, saying solutions from its comprehensive Resource Availability and Need project will arrive too late to avoid another outage-related emergency.
Clean Grid Alliance Executive Director Beth Soholt, of the Environmental sector, said MISO should study the cost of outages on the system. Robert Mork, of the Indiana Office of Utility Consumer Counselor, reminded executives of a mission statement that includes cost consciousness.
Murray said MISO might consider obtaining dispatch control of smart thermostats and electric vehicle charging stations to lower load when needed. “I would encourage people not to think about this one-dimensionally,” he said.
North Dakota Public Service Commissioner Julie Fedorchak suggested MISO begin collecting aggregate load and generation availability estimates from utilities for both the month and week ahead.
Wisconsin Public Service’s Chris Plante, of the Transmission-Dependent Utilities sector, pointed out that in some weeks, MISO’s maintenance margin is a negative number, indicating that generation operators have already taken too many outages. The RTO’s maintenance margin shows the amount of generation that can be taken out of service for a given time period without risking resource adequacy.
Representing the TDU sector, Madison Gas and Electric’s Megan Wisersky said it also believes MISO shouldn’t be handed control over outage scheduling.
“You want your unit on to make money from it. Generators tend to be very unique beasts, and you may only get consultants and specialists on your site at a specific time,” Wisersky said. “When MISO asks a unit to come off an outage, the unit is sometimes in pieces on the turbine floor. We’re not capricious in this … they’re not casual decisions.”
Murray said MISO’s new capacity advisory warning is a good step to help mitigate the effects of outages because units, if ready, will want to re-enter the market to scoop up the better prices available in a capacity shortage.
Multiple stakeholders said they would like MISO to attach economic signals to outage timing. Murray said the RTO could add to its markets an additional economic demand response product, which identifies a price to incent some load to get off the system. He also encouraged discussing an economic consequence if generation resources are unavailable during peak times. He brought up PJM’s Capacity Performance rules, though he said he wasn’t advocating use of a similar penalty in MISO.
Plante said MISO should revisit its proposal to create a seasonal capacity market to get a better idea of resource availability. He said MISO’s current capacity accreditation based on the summertime peak might not be the best route for resources such as wind facilities, which have their most productive months outside of summer.
Michael Curran, chair of the MISO Board of Directors, urged the RTO and stakeholders to “get everything on the table,” suggesting that the solution to poor outage coordination will be multifaceted, with more entities assuming more outage authority.
FERC last week denied a rehearing request but clarified an underlying order addressing MISO’s multi-value transmission projects (MVPs) (ER10-1791).
PJM, American Municipal Power and PJM transmission owners appealed the 2016 ruling, which came in response to the 7th U.S. Circuit Court of Appeals’ 2013 remand of a previous FERC order. The commission’s ensuing order determined that a limitation on MISO’s export pricing to PJM for MVPs was no longer justified, clearing the way for MISO to recover costs for those projects benefiting PJM customers by charging a fee on exports to PJM. (See MISO to Begin Charging Tx Fees on PJM Exports.)
In the order on remand, FERC said that given the growth of wind energy, as well as the need for PJM entities to access the resources and for MISO to deliver those resources to PJM, it was “appropriate to allow MISO to assess the MVP usage charge for transmission service used to export to PJM.”
Construction work on Ameren’s Illinois Rivers transmission project, a 345-kV line that included five multi-value projects. | Plocher Construction
MISO created the MVP category in 2010 for projects that address more than one reliability or economic need across multiple transmission zones. It originally intended to allocate project costs to all of its load and exports, but FERC excluded the export charge because of concerns over rate pancaking.
The commission rejected claims that it used the same evidence to justify the MVP charges’ application in the order on remand as it did to previously reject them. FERC said it reconsidered its previous determinations on this issue, including, but not limited to, findings made in previous decisions on the rate pancaking issue.
The commission said it centered its original decision on FERC Order 2000’s factors for determining appropriate RTO configuration, but it did not consider how the market-to-market (M2M) process affects those issues. In the order on remand, FERC found that the M2M process allows the RTOs to more efficiently address the inefficiencies and other issues arising along their seam, and noted that the grid operators added many “general improvements to coordination” between them since 2016.
FERC rejected PJM’s request to clarify that MISO must use the RTOs’ joint operating agreement process to review any MVP whose costs would be assessed on exports to PJM through the MVP usage rate, saying it was “based on a false premise.” The MVP usage rate is assessed only to customers voluntarily taking transmission service under the MISO Tariff and does not allocate the cost of every MVP to PJM.
The commission granted PJM’s clarification request regarding potential double recovery of the cost of certain MVPs, saying that when an MVP is selected in both RTOs’ regional transmission plans as an interregional transmission project, only the portion of an MVP’s cost allocated to MISO may be recovered in the MISO MVP usage rate.
FERC last week established a paper hearing to settle a dispute between PJM and an external resource on whether it should be allowed to pseudo-tie into the RTO even if doing so might raise congestion costs for members (EL18-145).
The order gives PJM 45 days to explain how it determined that Tilton Energy’s gas-fired facility failed the RTO’s market-to-market flowgate test, one part of its analysis of units outside of its territory that are attempting to become PJM capacity resources. The 176-MW facility located in Tilton, Ill., has been pseudo-tied into PJM for about two years and has cleared in each of the last two Base Residual Auctions. However, it cleared as part of a transition into stricter pseudo-tie rules that Tilton must pass by May 2019 in order to be eligible to offer into the BRA for the 2022/23 delivery year.
Tilton Energy Center | Google
In preparation for that, PJM analyzed the unit’s pseudo-tie and told Tilton in December that it’s not eligible for a pseudo-tie after the 2021/22 delivery year because 44 flowgates failed the RTO’s test. Although none of the flowgates is coordinated, they would all become eligible for coordination between PJM and MISO as a result of the Tilton pseudo-tie.
The test is intended to ensure that PJM assumes responsibility for coordinating a new flowgate to facilitate a pseudo-tie only if at least one internal generation resource also has a 1.5% flow impact on that flowgate, which the RTO considers “appropriate.” The test focuses on internal resources because PJM may use one to alleviate the impact on congestion caused by the external pseudo-tied resource.
Results
PJM found that the pseudo-tie affects 231 flowgates, of which 65 already were coordinated and 166 would newly become eligible for coordination. Of those 166 newly eligible flowgates, 44 did not meet the 1.5% threshold.
PJM is concerned that although MISO has not yet invoked its coordination rights to require PJM to take responsibility for Tilton’s effects on those flowgates, that doesn’t mean it won’t. The RTO says it wants to ensure the pseudo-tie wouldn’t alter its customers’ exposure to coordination costs in the event that MISO does so in the future.
Tilton argues that once a resource’s pseudo-tie passes the test, any subsequent changes to the system should not adversely affect the pseudo-tie, so the potential for flowgates to need to be coordinated in the future shouldn’t affect Tilton’s eligibility. American Municipal Power and Brookfield Energy Marketing filed answers in support of Tilton, agreeing that the test should only apply to flowgates that PJM and MISO have already designated as coordinated.
Brookfield argued that PJM’s interpretation of “each eligible coordinated flowgate” in its Tariff to mean any flowgate is “grammatically nonsensical, as ‘eligible’ clearly does not modify ‘coordinated’ but instead refers to the subgroup of coordinated flowgates.”
Hearing
Instead of hashing out the grammar, FERC set the matter for a paper hearing. The commission ordered PJM to explain four things:
How it determines a flowgate is impacted by a pseudo-tie under the terms of its joint operating agreement with MISO and how it identifies an “eligible coordinated flowgate” resulting from a pseudo-tie from MISO. That includes “a step-by-step description of the process and an explanation of its basis for doing so” and identifying any related processes that might depart from the JOA.
Whether it applies the 5% shift factor threshold in the JOA to determine “eligible coordinated flowgates” or, if not, why it does not, and whether the shift factor threshold, other specific thresholds set forth in the JOA, or some other screen would be a reasonable means of identifying flowgates for which coordination could be required.
How the flowgate test was applied to Tilton’s pseudo-tie, including an explanation of how PJM identified the “eligible coordinated flowgates” associated with the pseudo-tie and how PJM implemented each step of the test.
Whether PJM intends to request, or whether PJM expects MISO to request, coordination for any of the “eligible coordinated flowgates” identified for Tilton, and why or why not.
Tilton will then have 30 days to respond with testimony or evidence. The commission set the refund date for May 11, 2018, when Tilton filed the complaint.
Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members committees on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insiderwill be in Valley Forge, Pa., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
Consent Agenda (9:15-9:20)
Members will be asked to endorse:
B. Tariff and Operating Agreement revisions developed by the Governing Documents Enhancement & Clarification Subcommittee (GDECS).
1. PJM Manuals (9:20-9:35)
Members will be asked to endorse the following proposed manual changes:
A. Manual 1: Control Center and Data Exchange Requirements. Revisions developed to change system operator communication protocols while controlling facility constraints and data specification and collection requirements during outages.
Members will be asked to endorse a proposal and associated manual revisions developed by the Distributed Energy Resources Subcommittee that would give PJM and transmission owners better observability of behind-the-meter generation resources. (See “BTM Visibility,” PJM MRC/MC Briefs: Aug. 23, 2018.)
3. Market Seller Offer Cap Balancing Ratio Proposal (9:50-10:05)
Members will be asked to endorse a proposal approved by the Market Implementation Committee that would change how PJM estimates the expected future balancing ratio used in the default market seller offer cap. The proposed method would take the average balancing ratios during the three delivery years that immediately precede the Base Residual Auction using actual balancing ratios calculated during RTO performance assessment intervals (PAIs) of the delivery years, along with estimated balancing ratios calculated during the intervals of the highest RTO peak loads that do not overlap a PAI for any preceding delivery year with less than 360 intervals (30 hours) of RTO PAIs. (See “Balancing Ratio,” PJM Market Implementation Committee Briefs: July 11, 2018.)
4. Variable Operations and Maintenance (10:05-10:25)
Members will be asked to endorse a proposal documented in draft revisions to Manual 15: Cost Development Guidelines, the OA and Tariff. The proposal has been revised from what the MRC voted on previously to remove inclusion of fixed costs for energy resources and units that did not clear the capacity auction, and to include the variable operations and maintenance language in the OA and Tariff, meaning that the revisions would only be implemented with FERC approval. (See PJM Ponders Advancing VOM Effort over Objections.)
5. Quadrennial Review (10:25-10:45)
Members will be asked to endorse one of several proposed packages to revise PJM’s variable resource requirement demand curve as part of its quadrennial review. Among them are the RTO’s recommendations and a proposal from the D.C. Office of the People’s Counsel. (See “Concessions of VRR Curve Recommendations,” PJM Market Implementation Committee Briefs: Sept. 12, 2018.)
Members will be asked to endorse on first read one of six proposals and the status quo regarding alternative financial transmission rights default liquidation provisions and associated revisions to governing documents. If no proposal is endorsed, Citigroup Energy’s Barry Trayers is expected to move, and EDP Renewables’ John Brodbeck expected to second, a motion to extend the pending FERC filing to not offer the defaulted FTR positions for liquidation for an additional 90 days. (See GreenHat FTR Default a ‘Pig’s Ear’ for PJM Members.)
Members Committee
Consent Agenda (1:20-1:25)
Members will be asked to endorse:
B. Open Access Transmission Tariff and Reliability Assurance Agreement revisions associated with the registration process for aggregated seasonal demand response resources. (See “Seasonal Aggregation,” PJM MRC/MC Briefs: July 26, 2018.)
1. FTR Liquidation Process (1:25-1:45)
Members will be asked to endorse proposed OA and Tariff revisions associated with FTR default liquidation. If no proposal in agenda item 1.A is endorsed, then members will be asked to approve a motion to extend the pending FERC filing to not offer the defaulted FTR positions for liquidation for an additional 90 days. (See MRC item 6 above.)
2. Market Efficiency Process Enhancement Proposal (1:45-2:00)
Members will be asked to approve phase 1 of a proposal developed at the Market Efficiency Process Enhancement Task Force and associated OA revisions. (See “Market Efficiency,” PJM MRC/MC Briefs: Aug. 23, 2018.)
4. Variable Operations and Maintenance (2:30-2:45)
Members will be asked to endorse/approve proposed revisions to Manual 15: Cost Development Guidelines, the OA and Tariff regarding VOM. (See MRC item 4 above.)
5. Quadrennial Review (2:45-3:00)
Members will be asked to endorse proposed Tariff revisions associated with the quadrennial review of Reliability Pricing Model parameters. (See MRC item 5 above.)
6. Liaison Committee Charter (3:00-3:30)
Members will be asked to approve a motion to grant exceptions to the Liaison Committee charter addressing attendance at the Oct. 3, 2018, LC meeting with the Board of Managers. The exception brought by Greg Poulos, Consumer Advocates of the PJM States (CAPS) executive director, would allow RTO management and staff, state commission representatives, the Independent Market Monitor and FERC staff to attend the meetings.
Gov. Jerry Brown on Friday signed a legislative plan to help California utilities deal with the massive costs of wildfires sparked by power lines. But that measure’s proposal to let utilities sell bonds to pay for fires may not be an adequate solution to the bigger and more destructive blazes that appear to be the state’s new normal, some skeptics contend.
Going forward, California may need to establish a catastrophic wildfire fund or similar program to keep utilities solvent while quickly compensating wildfire victims, they said.
Simi Valley wildfire | U.S. Air Force
“The concept of having a pool of money on the front end that allows for rapid recovery is important,” said Jan Smutny-Jones, CEO of the Independent Energy Producers Association and former chairman of CAISO’s Board of Governors. “We need something more forward looking, a better approach.”
One proposal that failed to make it into the bill was a plan to establish state-regulated investment accounts that utilities could use to cover future wildfire costs, said Barry Moline, executive director of the California Municipal Utilities Association.
“We proposed not so much an insurance fund as a savings account,” Moline said. “The idea was to create this fund that utilities would pay into a little at a time,” with tax breaks as incentives, he said.
The plan proved too complicated to deal with in a limited time frame, but it could come up again next year, he said.
“It was a lot to wrap everybody’s head around in a short amount of time,” Moline said. “We took a month to work it out, and then there were only two weeks left of session.”
Another proposal was to create a program similar to the one Florida established for hurricane relief.
“We should be thinking about solutions like the Florida Hurricane Catastrophe Fund, which uses a modest surcharge on insurance policies to cover catastrophic losses,” Tom Long, litigation director for The Utility Reform Network, told lawmakers at an Aug. 9 hearing on SB 901.
That idea gained little traction because it essentially would have required those with sufficient homeowners insurance to subsidize those who are uninsured or under-insured, Moline said.
‘Big Uncertainty’
Lawmakers passed SB 901 shortly before concluding their two-year session at the end of August. It included some elements of a proposal Brown sent to the State Legislature in July.
Most of the proposals discussed prior to the bill’s passage had two goals: to compensate fire victims and to reduce the costs of holding utilities strictly liable for fire damages.
California extensively uses a legal procedure called “inverse condemnation” to make utilities pay for wildfires caused by electrical equipment, whether or not the utilities were negligent. Because the utilities can use eminent domain to take private property, the thinking goes, they should be liable for all damages to private property.
The result is that utilities often pay damages to fire victims without a long court battle over fault.
Inverse condemnation exists in almost every state, but California has used it far more broadly than any other jurisdiction.
That worked fine for decades, but recent fires have been cataclysmic, perhaps because of climate change. A series of blazes in Northern California’s wine country in October 2017, for example, could cost Pacific Gas and Electric more than $15 billion, according to some estimates.
As a result, PG&E’s stock has struggled in recent months and its financial solvency has been called into question.
“The possibility of that liability [for the 2017 fires] destabilized the utilities, lowering their bond ratings, which increased the cost of financing, which is ultimately borne by ratepayers since it increases the costs of the utilities,” said Kellie Smith, chief consultant to the conference committee that drafted SB 901.
Brown’s July proposal would have done away with inverse condemnation and strict liability. Utilities only would have had to pay for fires they’d caused through negligence.
The governor’s proposal was widely criticized by insurers, plaintiffs’ attorneys and ratepayer advocates, some of whom called it a bailout of PG&E.
A bipartisan panel of State Senators and Assembly members did not deal with inverse condemnation in the final version of SB 901. Instead, they drafted a plan that would allow the utilities to sell bonds to cover wildfire costs. The bond debts would slowly be repaid by additional charges on customers’ electric bills.
That didn’t make the utilities particularly happy, nor did it appease ratepayer advocates.
PG&E responded to a request for comment for this story by reiterating its general support for the bill but leaving open the possibility of future legislative action.
“While the legislation addresses many urgent needs, we must continue to work together to ensure ongoing investment in climate resiliency and clean energy, and to combat the devastating threat that extreme weather and climate change pose to our state’s shared energy future,” the company said in a written statement.
IEPA’s Smutny-Jones said it’s always been assumed that utilities could recover wildfire costs from ratepayers through incremental increases in electric bills. The magnitude of recent wildfires, however, calls that assumption into question, he said.
“That’s the big uncertainty,” he said.
If the state’s investor-owned utilities are destabilized, it could threaten California’s ambitious goals of largely relying on renewable energy sources, such as the wind- and solar-power generators that he represents, Smutny-Jones said.
It’s likely that how the state pays for wildfires will be an ongoing topic in Sacramento, he said.
“I think the Legislature will continue to be engaged on this issue,” he said. “Coming up with some sort of catastrophic wildfire fund or another insurance mechanism, we will continue to see activity in that area.”
