Page 1174 – RTO Insider

November 13, 2019

Fight Escalates over PG&E Settlement with Insurers

By Hudson Sangree

A fight over potential payments to insurers and wildfire victims has heated up in the Pacific Gas and Electric bankruptcy case and is scheduled to be a major topic of a hearing Nov. 19 before U.S. Bankruptcy Judge Dennis Montali in San Francisco.

Wildfire victims and California Gov. Gavin Newsom have challenged PG&E’s proposed $11 billion settlement with insurance companies and hedge funds — known in the Chapter 11 case as the subrogation claimants — that are seeking reimbursement for insurance payments.

PG&E has hailed the settlement as a milestone in its bankruptcy, which was brought about by billions of dollars in wildfire liability. The utility has asked Montali to approve the agreement at the Nov. 19 hearing.

Newsom’s lawyers, however, said in a court filing Friday that the settlement “is yet another example of legal maneuvering by parties apparently more focused on securing procedural advantages for their own pecuniary interests than on reaching a fair and expeditious resolution of this bankruptcy.”

“Many of the holders of subrogation claims are sophisticated financial institutions that bought the claims at a discount after the insurers paid out claims,” it said. “Certain of those institutions [including Boston-based Baupost Group] also hold equity in PG&E and may be seeking to leverage the settlement of subrogation claims to better position those holdings.”

PG&E Settlement — New homes rise amid dead trees in an area of Santa Rosa, Calif., destroyed by the Tubbs Fire in October 2017. | © *RTO Insider*

Newsom asked the judge to delay deciding the matter to allow a competitive process to play out between PG&E and a group of the utility’s bondholders, whose alternative Chapter 11 reorganization plan Montali admitted Oct. 9. (See Judge Admits Takeover Plan as PG&E Starts Blackouts.)

The governor said he wants to continue the closed-door mediation sessions he began with PG&E and its creditors, including wildfire victims, last week. The sessions include a retired bankruptcy judge whom Montali appointed as a mediator at PG&E’s request. (See Pressure Grows for Public Takeover of PG&E.)

The official Tort Claimants Committee (TCC), which represents fire victims, also objected to the $11 billion all-cash agreement. The settlement would lock up those funds, potentially to the detriment of fire victims, the TCC lawyers said. Insurance companies and financial speculators would be given priority, with no guarantee PG&E would have enough liquidity to pay victims’ claims, they said.

“It is time to call this settlement what it is: a mistake,” the TCC lawyers wrote. “The debtors have given away all their cash and placed the wildfire victims in a position of full risk in this case.”

In its current reorganization plan, PG&E has offered fire victims $8.4 billion in cash, but to increase its offer — as many expect will happen — the utility might have to offer a cash-stock combination, the TCC told the judge.

PG&E’s stock fell to a record low of $3.80/share Oct. 28 after it blacked out more than 2 million residents to prevent its from equipment sparking wildfires — yet it also fell under suspicion for sparking the 78,000-acre Kincade Fire in Sonoma County.

Its stock rebounded to $7.06/share at the close of trading Tuesday after several reports in the financial press that PG&E would increase its offer to fire victims to $13.5 billion, the same as bondholders proposed in their alternative reorganization term sheet.

Wildfire Liability Still to be Determined

The amount that fire victims may ultimately be owed is still in question.

PG&E and the TCC agreed Monday to extend the date for wildfire victims to file claims from Oct. 21 to Dec. 31, so that more claims may be submitted. There has yet to be an accounting of the number or amount of individual victims’ damage claims.

Proceedings to estimate the amount of PG&E’s wildfire damages are taking place before a different federal judge in San Francisco. The estimation process is a typical part of bankruptcies involving large numbers of victims.

And blame for one of the biggest fires of the past two years remains in doubt.

Investigators with the California Department of Forestry and Fire Protection (Cal Fire) determined PG&E equipment sparked the Camp Fire in November 2018. That blaze killed 86 people and destroyed more than 14,000 homes in the town of Paradise.

Cal Fire investigators also found PG&E equipment ignited 21 of the 22 wine country (also called North Bay) fires in October 2017.

They found a private landowner’s faulty wiring started the Tubbs Fire, which leveled an entire neighborhood in the city of Santa Rosa, killing 22 residents.

Victims, however, believe jurors should determine who’s to blame. A trial to decide if PG&E caused that blaze is slated to start Jan. 7. The result could add billions of dollars to PG&E’s wildfire liabilities.

November 13, 2019

Louisiana’s Campbell Expands Beef with SPP

By Tom Kleckner

Not content with pillorying SPP officials on their home turf, Louisiana Public Service Commissioner Foster Campbell has broadened his complaint over RTO expenses with a letter challenging SPP’s and MISO’s spending on offices and executive salaries.

Campbell last week filed a letter with SPP’s and MISO’s state commissions and the National Association of Regulatory Utility Commissioners’ senior leadership, calling for a “thorough examination of [grid operators’] spending.”

Campbell SPP — Louisiana PSC Commissioner Foster Campbell | © *RTO Insider*

“Turning the American power grid into the electricity equivalent of an interstate highway system is probably a worthwhile goal, but I question how those RTOs freely spend our dollars,” Campbell wrote, adding a new acronym to the industry’s lexicon: Overspending Other Peoples’ Money (OOPM).

The Louisiana commissioner described SPP’s Corporate Center as a “150,000-square-foot Taj Mahal of an office building in a leafy 20-acre suburban setting fit for a Fortune 100 corporation.” He said he hasn’t been to MISO’s corporate offices in Carmel, Ind., and was thus unable to compare them to SPP’s “ornate offices.”

“If MISO’s offices are anything like SPP, then these two [RTOs] have a bad case of OOPM,” he said.

Campbell also lambasted the salaries paid to the grid operators’ top executives. He noted SPP’s Nick Brown and MISO’s John Bear are paid eight and 16 times, respectively, as much as FERC Chairman Neil Chatterjee ($155,500). Campbell cited 2017 data for Brown ($1.5 million in total compensation) and said Bear receives $2.8 million in compensation.

Bear’s salary matches up with the 2017 IRS Form 990 available through nonprofit tracker GuideStar. Brown’s 2016 Form 990 shows his total compensation was $1.2 million.

Campbell contrasted the CEOs’ salaries with Louisiana’s “1.6 million electric customers, many of whom live at or below poverty level.” He said SPP and MISO charge the state’s investor-owned utilities nearly $31 million a year to dispatch energy.

The letter would sound familiar to those who were present last month in Little Rock, Ark., when Campbell livened up the SPP Regional State Committee’s October meeting at the RTO’s corporate headquarters by criticizing the facility’s $62 million price tag and senior executives’ salaries. Several observers found his comments to be political, as Campbell is up for election next year. (See “Louisiana’s Campbell: SPP Spending ‘Extravagant,’” SPP Regional State Committee Briefs: Oct. 28, 2019.)

SPP said it “respectfully but wholeheartedly disagrees” with Campbell’s allegations.

Spokesman Dustin Smith said the grid operator provides “significant” savings to ratepayers in its footprint and listed several examples to back up his point:

The $570 million in savings to participants in the Integrated Marketplace.
“Conservative” cost-benefit studies that indicate the RTO’s services produce $2.2 billion in annual savings across its 14-state region.
FERC’s 2018 State of the Markets report indicating the SPP region enjoys the nation’s lowest wholesale electric costs.

“To anyone who questions SPP’s affordability, stewardship or ethics, we welcome the opportunity to provide answers,” Smith said.

MISO spokesperson Allison Bermudez would only say that the RTO, “as we have for the past 20 years, continue to be good stewards of our members and those customers we work together to serve.”

Louisiana utilities Entergy Louisiana and Southwestern Electric Power Co. both said RTO membership is worth the costs.

Entergy spokesman Mike Burns said the company’s MISO membership has been a “highly effective tool in helping control costs and keeping our rates among the lowest in the nation.” After netting out the RTO’s administrative costs, Louisiana customers realized an estimated $560 million in savings between 2014 and 2018, “largely because of MISO’s organized power markets, which allow power plants to be dispatched more efficiently, resulting in a lower delivered cost of energy,” he said.

“Customers also see significant cost savings from MISO members sharing generation reserves across the organization’s footprint, producing long-term benefits,” Burns said.

SWEPCO’s Peter Main said the utility’s customers benefit from SPP’s regional markets through reduced fuel costs and more efficient transmission planning. However, he also said SWEPCO is concerned about the RTO’s rising costs. SPP’s Board of Directors last month approved a record increase in the administrative fee, from 39.4 cents/MWh to 43 cents. (See “Directors Approve 9.1% Administrative Fee Increase for 2020,” SPP Board of Directors/MC Briefs: Oct. 29, 2019.)

“SWEPCO and other SPP members remain concerned about the growing costs of RTO operations,” Main said. “We are actively involved in efforts to ensure that the RTO is cost-effective, efficient and providing good value for our customers.”

SPP is equally concerned about costs. First-year board Chair Larry Altenbaumer created and led a task force focused on finding opportunities to increase value and improve affordability for SPP’s members and stakeholders. The group determined there is work to be done around the edges. (See SPP Value Group Finds No ‘Silver Bullets.)

RTO Insider asked regulatory commissioners in both regions for comment on Campbell’s letter. Arkansas’ Kimberly O’Guinn and Missouri’s Scott Rupp responded.

O’Guinn, who is the RSC’s president this year, said she didn’t agree with Campbell’s assessment, but she “appreciated” his concerns about the costs of participating in SPP.

“The RSC is conscious of SPP’s costs as well as other issues that impact utilities and ultimately the customers,” she said. “Therefore, the majority of the RSC regularly participates in monthly calls and quarterly business meetings to educate ourselves on these matters and engage in dialogue with the SPP Board of Directors and staff, members and stakeholders.”

O’Guinn said the Arkansas Public Service Commission finds that SPP’s services and the Integrated Marketplace have “resulted in net benefits to ratepayers” and justified the commission’s decision to allow certain utilities to transfer functional control of their transmission assets.

“Along with financial benefits,” she said, “participation in SPP has provided increased reliability and a decrease in required reserve margins.”

Rupp said the Missouri Public Service Commission believes “there is a large amount of benefit from RTO membership.” He cited back-of-the-envelope figures from SPP’s last regional cost allocation report that indicated Evergy’s Missouri subsidiaries Kansas City Power & Light and KCP&L Greater Missouri Operations enjoyed 3.97 and 2.15 benefit-to-cost ratios, respectively.

He also said the PSC requires the state’s utilities to file studies every three years that justify their RTO membership.

“In the past few years we have waived the study, believing firmly that benefits are realized and the cost of the study would not be a good expenditure of resources,” Rupp said.

He also noted that that there have been few instances of load shed despite recent severe storms and floods in Missouri. “Before RTO membership, there would have been a shedding of load in Missouri.”

Amanda Durish Cook contributed to this article.

November 12, 2019

Overheard at NECA 2019 Power Markets Conference

WESTBOROUGH, Mass. — The Northeast Energy and Commerce Association (NECA) last week drew more than 100 participants to its 18th Power Markets Conference to explore grid reliability and resilience, carbon pricing, and the federal and state policies impacting the electricity sector.

Conference co-chairs Mary Usovicz, principal of MUConnections, and David Fixler, an attorney with Greenberg Traurig, mixed up the format by doing away with slide presentations — mostly — and just having panelists say a few words before taking audience questions and polls via Slido, a web-based platform.

Following are highlights of what we heard.

NECA Power Markets — The Northeast Energy and Commerce Association held its 18th annual Power Markets Conference on Nov. 7. | © *RTO Insider*

‘Dangerous Road’ for Markets

FERC Commissioner Richard Glick shared his perspective on the power markets after two years in office.

“Chairman [Neil] Chatterjee gave a speech a couple months ago in which he said he wanted to make FERC boring again,” Glick said. “Well, I don’t think he’s succeeded yet on that. It’s been pretty crazy lately.”

FERC Commissioner Richard Glick | © *RTO Insider*

He said the “sometimes too emotional” commission meetings were “emblematic, unfortunately, of the governmental environment, at least related to the federal government these days.”

The heated battles partly stem from how the transition to a new energy world inevitably creates winners and losers, Glick said. There’s “a lot of money” involved, he added.

“When you have a dissent or disagreement and this kind of doctrinaire policy — that’s my view — a lot of these issues end up getting litigated in a court, and all that does is create more uncertainty for you all in the industry,” Glick said. “It doesn’t mean you’re guaranteed to survive a court challenge if there’s a unanimous commission, but certainly it’s much more likely.

“I never realized until I got to FERC how complicated some of these markets have grown … and we see a lot of proposals to tinker with the markets, particularly the capacity markets,” Glick said. “There’s a very broad difference across the country in how the RTOs and ISOs address resource adequacy,” from highly structured markets in the East, to utility-centered planning elsewhere, to total market reliance in ERCOT.

Left to right: Rebecca Tepper, Massachusetts attorney general’s office; Matthew Nelson, Massachusetts DPU; Deborah Donovan, Acadia Center; and Barry Hobbins, Maine Public Advocate | © *RTO Insider*

In the debate over federal and state energy policies competing in some way, Glick said the Federal Power Act “is very clear.”

“Resource decision-making is supposed to be left to the states, not to the federal government. The Supreme Court has spoken, and there are limits on what states can do — they can’t set wholesale prices and so on … but for the most part the court was also relatively clear that … it’s up to the states, not FERC, to make resource decisions.”

Glick pointed to frustration with the lack of a federal carbon policy, leading states to decide to go their own way on carbon pricing or emissions standards, a process that produces its own complications — and risks — for organized electricity markets.

“What we’re seeing is the real danger that we’re going to unravel completely these markets,” he said. “Some people might think that’s a good idea, some not, but if you do support markets, it’s a very dangerous road to go down to continue to stifle the states’ efforts.”

State Perspectives

Rebecca Tepper, Massachusetts attorney general’s office | © *RTO Insider*

During one panel, Rebecca Tepper, chief of the Massachusetts attorney general’s energy and telecommunications division, asked how the wholesale markets would have to change in order for Massachusetts to bring on more renewables without state-sponsored procurements.

“We are looking at transitioning the current fleet [of generators], and the Department of Environmental Protection is looking at every cap on natural gas emissions on a declining basis, but we recognize that fossil [fuel] is going down and we have to replace that,” Massachusetts Department of Public Utilities Chair Matthew Nelson said.

“At the same time, the state is also trying to move transportation and buildings over to the electric grid, so electric’s probably going to be growing,” Nelson said. But he acknowledged he didn’t know what prices the ISO-NE market would have to produce to discontinue procurements.

Matthew Nelson, Massachusetts DPU | © *RTO Insider*

Asked if there is a breaking point price for electricity consumers, Nelson quipped that his staff would advise him not to answer that question.

“Who wouldn’t want electricity? It’s the closest thing we have to magic,” Nelson said.

On the subject of carbon pricing, Nelson said, “When people see something as complex as a clean peak standard in a single state, you start thinking, ‘Is a regional carbon adder the right way to go?’ If we’re going to design a carbon adder … we don’t want to set a price that fails to impact the market the way we want it to.

“I think RGGI is great, and I like carbon pricing, but is that the thing that is bringing offshore wind on? Is that price or policy sufficient to bring energy storage; to support a Millstone? Those are the questions we have to answer when we are thinking about what a carbon price is in the market.”

Cynthia Arcate, CEO of PowerOptions, asked, “What is the path forward for renewables if there is insufficient demand for” Competitive Auctions with Sponsored Policy Resources (CASPR)?

Mark Karl, vice president of market development for ISO-NE, who earlier referred to CASPR as “the friendly ghost,” said the question goes to the heart of what the New England States Committee on Electricity “is asking all of us to work on, collectively, which is, ‘How do we manage these resources?’”

“I think of CASPR not as a friendly ghost, but as the ghost of a promise that we in the states were going to be able to incentivize renewable resources,” said Marissa Gillett, chair of the Connecticut Public Utilities Regulatory Authority. “We need more work by the states.

“You’re never going to get [carbon pricing] from the states, because we are not eager to make anything else FERC-jurisdictional at this moment.”

Defining the Future

Seth Kaplan, director of permitting and development for Mayflower Wind, which just won Massachusetts’ second 800-MW offshore wind solicitation, brought up the potential for the region to export energy to the Midwest, where older fossil resources are retiring. “There were [U.S. Department of Energy] transmission studies 12 years ago that modeled that with a full build of offshore wind generation and onshore transmission,” he said.

Seth Kaplan, Mayflower Wind | © *RTO Insider*

After another speaker referred to wind turbines as “intermittent,” he also gave the audience a vocabulary lesson, saying, “Words matter.”

“All energy sources are to some degree intermittent,” Kaplan said. “Nuclear power plants sometimes go offline. … That’s intermittent. Variable is predictable. We can give you a 90% case that tells you how much energy a wind farm will produce over the course of a year, and that’s what you can plan around.”

Deborah Donovan, Massachusetts director for the Acadia Center, was asked how to tell the difference between the goal of zero carbon, carbon-free electricity, reduction of carbon emissions by 100% and net carbon neutral.”

“There are some subtle differences,” Donovan said. “First of all, it does matter whether we’re talking about an economy-wide target versus a sector-specific target, because not all these terms apply to all situations.”

Following what the U.N. Intergovernmental Panel on Climate Change says about net zero carbon, “that definition is that manmade carbon additions are being balanced by manmade carbon removals, so those could be other actions like reforestation,” Donovan said.

Dan Dolan, president of the New England Power Generators Association, called for an “analysis and articulation” of future market needs at the same depth with which the RTO has been studying fuel security.

“The second component is trying to identify what is the most common element driving these [state] procurements and other entry into the market,” Dolan said. “And pretty clearly it’s carbon; it’s meeting the economy-wide mandates that the states have. A dual and second track to all this is a meaningful look at what it requires on an economy-wide basis … to try and obviate the need for a second wave of contracted resources.”

The morning keynote speaker said that on carbon he was only repeating what ISO-NE CEO Gordon van Welie, FERC commissioners and many others have said in the past.

“The cure for what ails the markets, or at least its biggest problem if you think we should be trying to integrate renewables and keep nuclear plants running without depressing prices, is a carbon fee,” said Rich Heidorn Jr., editor-in-chief of RTO Insider. “Incorporate the externalities, and you could reduce [ISO-NE’s] meeting schedule, and FERC’s workload, quite a bit.”

– Michael Kuser

November 12, 2019

General Counsel Vince Duane Leaves PJM

By Christen Smith

PJM’s year of high turnover continued this week with the departure of Vince Duane, the RTO’s senior vice president and general counsel.

PJM Duane — Vince Duane | © *RTO Insider*

PJM announced Duane’s resignation, effective immediately, via email Monday. In the release, the RTO said Duane will seek other opportunities after more than 16 years with the organization.

“We are grateful to Vince for his many contributions to PJM and its stakeholders over the past 16 years,” interim CEO Susan Riley said in a statement. “As a member of the PJM Board of Managers, I worked with Vince from the time I joined the board and have enormous respect for his legal perspective. The entire PJM community thanks Vince for his many contributions to PJM.”

Deputy General Counsel Chris O’Hara will assume the role of vice president, general counsel and corporate secretary with responsibility for law and compliance, effective immediately, PJM said.

“It has been my honor and privilege to serve PJM’s employees and members for more than 16 years,” Duane said. “I am proud to have been part of such an outstanding team doing extremely important work, and I know PJM will continue to forge ahead with innovation, integrity and outstanding service to its members.”

Susan Buehler, PJM spokesperson, didn’t elaborate much further on Duane’s departure, except to say that it “was purely his decision” and that he was ready to move on and “do something else.”

Duane is the fourth top executive to leave PJM this year, following the resignations of CEO Andy Ott, CFO Suzanne Daugherty and Vice President Denise Foster. In September, Riley announced the restructuring of the State and Member Services Division, previously led by Foster and now headed by Jen Tribulski, senior director of member services, and Asim Haque, executive director of strategic policy and external affairs.

Several key leaders within PJM also received promotions over the summer, announced at the time of Ott’s resignation. (See CEO Andy Ott to Retire.) The organization also hired Nigeria Poole Bloczynski as its first chief risk officer in July and hopes to choose a new CEO before the end of the year. (See PJM Names Chief Risk Officer and “CEO Search Continues,” PJM MRC Briefs: Sept. 26, 2019.)

November 12, 2019

Settlement Hearing Set for PJM Border Rate Dispute

By Christen Smith

FERC encouraged PJM’s transmission owners to settle disputes over the sector’s proposed Tariff attachment that revises outdated border and non-zone service rates using a methodology that several members find flawed and unreasonable.

The filing, sent to FERC in June, updates the yearly border charge to prevent network integrated transmission service (NITS) customers — network load located outside PJM’s boundaries but served from within the RTO — from subsidizing border and non-zone service rate customers who use transmission service through and out of PJM (ER19-2105). In the filing, TOs said under existing rates, last updated in 2004, it’s unclear if border rate customers “have been consistently charged transmission enhancement charges (TECs)” because of the ambiguity around which specific TECs apply to border service.

“The PJM TOs argue that the proposed revisions will end the cross subsidy that zonal NITS customers in PJM have been providing to border rate and non-zone service rate customers because revenue from customers taking service under each of these rates is either directly or eventually credited back to zonal NITS customers,” the commission noted in its order.

The proposal would not increase the total cost of providing transmission service in PJM because the increases to border and non-zone service rates will be offset by a decrease for zonal NITS customers, the TOs said in their filing.

FERC accepted the TOs’ filing Nov. 5, subject to refund, with an implementation date of Jan. 1, 2020, but also set a paper hearing and settlement procedures for involved parties to work out their differences over the proposed methodology behind the rates.

Contentions Raised

In proposing the rate revision, TOs wanted to clarify that PJM’s border service includes service to a point of delivery at a merchant transmission facility (MTF) that provides service to a neighboring transmission system — an unnecessary explanation, according to some of the protesters in the proceeding.

The New York Power Authority suggested the clarifying language “is an attempt to create a separate and unjustified classification of customers for purposes of extracting a higher point-to-point transmission service rate from such customers.”

Linden VFT, a New Jersey-based MTF, said the new methodology would increase its border rate charges from $6 million annually to roughly $16 million, potentially forcing the company into insolvency because of “fundamental changes” to its business model. It also objected to a formula that it insists charges the company for lower-voltage transmission facilities “it does not use.”

The TOs offered a solution for double charging of MTFs with firm transmission withdrawal rights (FTWRs): create a credit that would remove the cost of those TECs paid in connection to a facility’s FTWRs from the cost of border rate service.

The Long Island Power Authority argued the crediting mechanism will not work, and the Neptune Regional Transmission Authority supported the claim, noting that the TOs “crediting mechanism is structurally flawed and would result in MTFs with FTWRs and their customers being charged twice for the same allocation of [Regional Transmission Expansion Plan] charges.”

FERC Weighs in

FERC dismissed Linden’s argument that the proposed border rate would charge the company for lower-voltage transmission facilities it does not use, saying “the border rate reflects the fact that a transmission customer may take border rate service from any point within PJM, and that the entire PJM transmission system, including lower-voltage transmission facilities, supports the export transactions.”

“The border rate service, therefore, permits the exporter to access generation anywhere in PJM and such transmission may utilize any of the PJM facilities, including lower-voltage lines,” the commission concluded.

FERC also allayed concerns over the TOs clarifying language on the definition of border service, saying that it is just and reasonable and aligns with commission precedent on the definition of “through and out service.”

Other concerns over whether the proposal meets the standards for formula rate protocols were also dismissed. FERC said because the stakeholders can contest PJM TOs formula rates, there is no need for additional protocols regarding the proposed composite rate. The commission did agree, however, that the TOs’ filing “lacks clarity regarding the process by which parties can challenge or confirm PJM’s calculation of the border rate from the PJM TO’s formulas.”

FERC said a settlement judge will be assigned within 15 days of the filing. The appointed judge will report to the commission within 30 days concerning the status of settlement discussions. At that time, the judge can recommend additional time for settlement negotiations or commence a paper hearing.

The commission granted late-filed motions to intervene from Exelon, PPL and Helix Ravenswood.

November 12, 2019

NYISO Business Issues Committee Briefs: Nov. 6, 2019

NYISO’s Business Issues Committee on Wednesday voted unanimously to recommend that the Management Committee approve Tariff changes intended to help speed up the interconnection process.

Thinh Nguyen, senior manager for interconnection projects, presented the proposed changes, which seek to expedite the class year portion of the interconnection study and limit the potential for one or two projects to cause delay for other projects.

NYISO is proposing to:

require deliverability evaluation in system reliability impact studies;
remove additional system deliverability upgrade studies from the class year study;
conduct expedited deliverability studies for capacity resource interconnection service (CRIS)-only projects; and
tighten CRIS expiration rules to prevent the retention of CRIS by facilities not participating in the capacity market.

Nguyen noted that stakeholders were keen to ensure the proposal would not change the qualities of the current process most important to them, including:

the identification of system upgrade facilities for projects to reliably interconnect, including detailed design, engineering and construction estimates;
provision of binding, good-faith cost estimates that provide reasonable closure on upgrade costs; and
equitable allocation of upgrade costs.

NYISO intends to make many of the proposals effective for Class Year 2019.

Competitive Entry Exemptions

The committee also voted unanimously to recommend that the MC approve Tariff changes to make competitive entry exemption (CEE) available to requests for additional CRIS megawatts in a manner consistent with the underlying rationale for the exemption.

Senior ICAP Mitigation Analyst Jonathan Newton presented the proposal, which includes a change in the consequences of withdrawing a CEE request or providing false and misleading information.

The changes also modify the CEE rules in a way that could facilitate the repowering and replacement of existing generators by allowing existing portfolio owners that have entered into competitive short-term hedging contracts to qualify for the CEE.

“The changes are a reasonable way to let people move forward without penalizing normal commodity hedging,” one stakeholder said.

NYISO intends to make the proposed rules effective for Class Year 2019 projects, Newton said.

If the MC approves the queue changes this month, and the Board of Directors approves them in December, the ISO anticipates making the filings with FERC by Dec. 20 and seeking orders from the commission during the third week of February 2020.

More Granular Operating Reserves

The BIC discussed a proposal to implement local reserve requirements in certain New York City (Zone J) load pockets.

Market Design Specialist Ashley Ferrer presented the proposal, as recommended by the Market Monitoring Unit, including the modeling of the requirements based on N-1-1 reliability criteria.

Load pockets in Zone J are areas constrained by load levels and generation capability, as well as by transmission-supported import levels into the pocket. The structure and boundaries of each load pocket varies based on load, generation and transmission imports, Ferrer said.

The ISO last June established a reserve region in Zone J based on a market design approved by stakeholders in March.

NYISO is proposing to establish operating reserve demand curves for each load pocket that assign a $25/MWh value to the proposed reserve requirements. The ISO proposes 30-minute reserve requirements of 325 MW in Astoria East/Corona/Jamaica; 225 MW in Astoria West/Queensbridge/Vernon; and 250 MW in Greenwood/Staten Island.

“This issue is not prioritized in 2020, but we still consider it important, and it could go forward conceivably in 2021,” said Rana Mukerji, senior vice president for market structures. “We will actually bring forth the methodology [for an impact analysis] before conducting any consumer impact analysis [with respect to the proposal].”

Broader Regional Markets Report

In presenting the month’s Broader Regional Markets Report, Mukerji highlighted updates to two ongoing proceedings.

The first item concerned five-minute real-time dispatch transaction scheduling with Hydro-Québec (HQ) across controllable interties at the Chateauguay proxy.

The proposed plan includes a project to consider scheduling transactions on a five-minute basis with HQ, instead of either the 15-minute or hourly basis currently in effect using NYISO’s real-time commitment software. The ISO is targeting to complete a study of the potential enhancement in 2020.

The second item concerned an effort to clarify the minimum deliverability requirements for external capacity.

At the MC’s May 20 meeting, stakeholders approved enhancements to the performance requirements for external capacity suppliers in response to a supplemental resource evaluation, a proposal that became effective in August after FERC approval.

IPPNY’s Matt Schwall Elected as Vice Chair

The BIC elected Matthew Schwall as its incoming vice chair for 2019/20. Schwall is director of market policy and regulatory affairs for the Independent Power Producers of New York, where he has worked since 2014, and previously worked in various capacities at the New York State Assembly. He is earning a master of science in global energy management at the University of Colorado Denver.

— Michael Kuser

November 12, 2019

SPP Seams Steering Committee: Nov. 6, 2019

SPP staff last week told the Seams Steering Committee that they have begun “very preliminary” interregional planning discussions with Canadian electric utility SaskPower.

Clint Savoy, the committee’s staff secretary, said a provision in the RTO’s joint operating agreement with SaskPower allows joint planning analysis and coordinated system planning. The discussions center on reliability needs, he said.

SPP and SaskPower share a direct tie through Basin Electric Power Cooperative’s existing transmission facilities in North Dakota. The grid operator completed its first international transaction in December 2015 when it imported power from SaskPower during an emergency situation. (See SPP, SaskPower Make First International Trade.)

In February 2017, the Department of Energy granted SPP’s request to make electricity exports to Canada. The RTO told the department that it wanted to “address emergency assistance transactions” but that it doesn’t normally purchase from or sell to “such external entities.”

The authorization expires on Feb. 7, 2022.

FERC in 2016 approved SPP’s request to recognize the U.S.-Canadian border as a point of sale for transactions with Canadian transmission providers. The ruling allows Canadian companies to register their resources with and make them available to the RTO under its market rules. (See “FERC OKs Canadian Border Point-of-Sale Filing,” SPP Briefs.)

Pseudo-tie Revisions to SPP-MISO JOA

The SSC reviewed and made changes to a new pseudo-tie section of SPP’s joint operating agreement with MISO, addressing its neighbors’ continued deferral of dispatch decisions to its balancing authorities.

MISO has historically deferred to local BAs in making pseudo-tie decisions in the real-time transfer of a resource or load from its “native” BA to an “attaining” BA in a different location.

“There are some local balancing authorities taking the position that we’re not a BA, so we’re not going to execute it anymore,” Savoy said. “We thought it would be helpful to address this in the JOA and avoid those situations in the future.”

Savoy said staff have taken FERC-approved language from the MISO-PJM JOA as a starting point. SPP hopes to file the changes with FERC early next year.

M2M Settlements Swing in MISO’s Favor

Staff’s regular market-to-market (M2M) report indicated another slow month, with 41 permanent and temporary flowgates binding for a total of 664 hours and resulting in a $197,320 settlement in MISO’s favor.

August’s numbers dropped to $64.1 million in SPP’s favor. The two seams neighbors began the process in March 2015. SPP has seen positive settlements in 40 of 54 months through August.

— Tom Kleckner

November 12, 2019

CAISO Black Start Project Must Divulge Cost Info

By Hudson Sangree

FERC accepted an agreement last week between CAISO and a Calpine plant to provide black start service, but it also agreed with the California Public Utilities Commission that more cost information was needed to determine if the deal was just and reasonable (ER19-2800).

The federal commission accepted the agreement effective Nov. 6 but required additional information to be presented at settlement hearings.

CAISO in 2016 determined it needed additional black start capability in the San Francisco Bay Area. It issued a request for proposals in June 2017 and ultimately selected a plan by Calpine to provide battery storage at the company’s gas-fired Russell City Energy Center in the city of Hayward.

The agreement between Russell City and the ISO — in which Pacific Gas and Electric, the transmission provider in Hayward, is also a participant — stipulates that the plant will collect about $7.4 million annually for five years to cover a $21.8 million capital investment and earn a reasonable rate of return. The plant owner will recover both the variable cost of providing black start service and the fixed cost of constructing the battery system.

The variable cost represents the sum of a start-up charge, a fired-hours charge, greenhouse gas reimbursement, CAISO charge reimbursement, a performance test field support charge and a power plant outage cost reimbursement — all outlined within a schedule of the agreement. The contract also provides for Russell City to recover a “market revenue shortfall” if the revenues received during energy delivery are less than provided for by the schedule.

Russell City contends that CAISO’s competitive solicitation process guarantees that its rates, terms and conditions for black start service are just and reasonable. The ISO would have the option to renew the agreement for an additional five years after the contract expires.

In its comments to FERC, the CPUC said it supported the development of black start capability in the Bay Area but argued Russell City had not provided underlying cost information to support its filing. The state commission requested that FERC require Russell City to refile the agreement with underlying cost information, or alternatively accept the agreement but also determine that it does not set any precedent. FERC agreed with the CPUC’s concerns.

“Although Russell City, CAISO and PG&E represent that they exchanged information with CPUC about cost allocations during their negotiations of the agreement, that information has not been submitted into the record of this proceeding and therefore is not available for this commission to evaluate in determining whether the proposed rates are just and reasonable under Section 205 of the Federal Power Act,” the commission found.

November 12, 2019

Testing Looms for MISO Cloud-Based Market Platform

Three years into the project to replace its market platform, MISO is now set to begin moving information to its new private cloud to begin testing.

MISO Director of Digital Delivery Foundations Kevin Larson said the RTO has completed much of the platform design work this year and will next year focus on upgrading technology infrastructure. He said it is making sure the platform is adaptable.

“We’re focused on the performance of the day-ahead clearing of the market engines: How fast can we do that with all the new [market] products and services?” Larson told stakeholders at a Market Subcommittee meeting Thursday.

He said MISO’s motto regarding the new cloud-based platform is “continuous integration, continuous delivery,” allowing for more regular improvements instead of “a few big deployments infrequently” using the existing server-based platform.

“As we look into 2020, we’re going to start migrating applications to the MISO private cloud,” Larson said. (See New MISO Platform Headed to the Cloud.)

MISO still expects to announce its preferred vendors on the platform build by the end of the year. So far, General Electric is still the major vendor.

“We’ve now had some early software deliveries for testing, and it’s been solid,” Executive Director of Digital Strategy Jeff Bladen told the Board of Directors in September.

Bladen said the quality of the software was up to MISO standards, and GE’s performance was much improved from its earlier delays. Board members at the time were pleased with the turnaround. (See “Vendor Delay on Market Platform Replacement,” MISO Board of Director Briefs: June 20, 2019.)

“We’re pleased to say early results are quite positive and encouraging,” CEO John Bear reported at the Oct. 22 Informational Forum.

MISO executives will deliver another market platform update at the Dec. 12 board meeting in Indianapolis.

— Amanda Durish Cook

November 11, 2019

Strategy Plan Prompts ‘Cost-benefit’ Discussion at MRC

By Rich Heidorn Jr.

ATLANTA — NERC’s briefing on its revised ERO Enterprise Long-Term Strategy last week prompted a discussion on whether it is feasible to apply cost-benefit analyses to reliability standards.

In their comments on the strategy plan, both the National Rural Electric Cooperative Association and the Electricity Consumers Resource Council urged NERC to incorporate a cost-benefit analysis before adopting future standards.

NERC Long-Term Strategy — Sylvain Clermont, Hydro-Québec | © *ERO Insider*

“We’ve been struggling with that issue for a while,” Hydro-Québec’s Sylvain Clermont said during the discussion at the Members Representative Committee’s quarterly meeting. “It’s like an oasis in the desert. We know there is an oasis in the desert. We even think we heard someone who saw the oasis. But nobody can quite find the oasis.”

“This is a really tricky area,” NERC Board of Trustees Chair Roy Thilly said. “Every survey we have done points out that stakeholder concern that cost really be considered in the standard [development] process.”

But doing a formal cost-benefit analysis before implementing a standard is difficult, Thilly said. “The effect on one entity may be very different than the effect on another entity, given where they already are in dealing with the issue.”

Industry can help NERC determine the least-cost way to accomplish the goal of a standard, he said. And an after-the-fact review once there is experience with a standard may be possible. “There may be much better information” then, he said.

Cost Effectiveness More Realistic?

Clermont agreed that cost effectiveness may be a more realistic goal.

“If there are two ways to implement a standard, which is more effective than the other one? That’s perhaps an easier question than is there a [positive] cost-benefit or is there a business case to develop a standard,” he said. “I would say that there is most likely never a business case to develop a standard.”

NERC CEO Jim Robb said the ERO is aware of the industry’s challenge in funding improvements for security and resilience “against the backdrop of flat to no load growth in many jurisdictions.”

“Everyone, when they cast a vote for a standard or against a standard, is making their own assessment as to whether or not it’s worth the [cost]. I don’t think we ever want to get to the point where we have a big econometric department at NERC … but I think we want to make sure we are reaching out and getting input from industry so the work we do is economically informed, even though that’s on the fringes of our mandate.”

State/Municipal Utility sector representative Carol Chinn of the Florida Municipal Power Agency said it would be helpful to “have compliance in the room when standards are developed.”

“I think there’s a lot of unknowns when standards are approved about how can you comply with it. These things are complex. When you look at, for example, CIP-003 … it’s [effective] Jan. 1. What are the expectations for compliance? What do we need to do?”

The strategy document was revised following comments from six industry groups, which also included the Edison Electric Institute and the ISO/RTO Council. It is set to be brought to an endorsement vote at the board’s Dec. 12 conference call after input from regional entities.

‘Focus Areas’

The new plan is based on four “Enterprise Value Drivers”:

Organizing and deploying top talent.
Developing and delivering innovative and risk-based programs and tools.
Collaborating effectively with industry and other stakeholders.
Maintaining independence and objectivity.

It identifies five “strategic focus areas”:

Expand risk-based focus in all standards, compliance monitoring and enforcement programs.
Capture effectiveness, efficiency and continuous improvement opportunities.
Assess and catalyze steps to mitigate known and emerging risks to reliability and security.
Build a strong, Electricity Information Sharing and Analysis Center-based security capability.
Strengthen engagement and collaboration across the reliability and security ecosystem in North America.

“We recognize that the electric system as it is today isn’t our grandfather’s electric system. … Lots of changes [are] coming at us in a lot of different directions,” Robb said. “So we always need to be thinking about … whether the programs we execute — many of which were designed 10 to 12 years ago — are still the right programs.”

The goal, he said, is “keeping eyes on the big issues [and] not getting distracted by the trivial.”

“Many of the things that we do have their roots in not only reliability and security but also … the resilience of the system, so you’ll see more references to resilience in the new document” than the 2017 s trategy document it will replace, Robb said.

Funding

Andy Dodge, director of FERC’s Office of Electric Reliability, asked about the new plan’s reference to investigating “funding mechanisms” to support NERC’s mission.

NERC Strategy Plan — The ERO Enterprise “Golden Circle” | *NERC*

Robb said that was a “placeholder” for potential programs that could be structured like the Cybersecurity Risk Information Sharing Program, which is funded by industry and the Department of Energy rather than the Federal Power Act Section 215 assessments that fund the ERO’s operations.

“A number of important issues that get identified in our various assessments … end up with a recommendation that says someone should do X and someone should do Y. And in many of those cases, we don’t really have any ability for establishing accountability as to who’s actually [going to] get it done,” Robb said.

“For example: new planning models … that would be necessary to address variability of resources on the system. … That’s not something we have the expertise to do in-house ourselves, but it’s something that’s very important to be developed,” Robb continued. “Maybe four or five entities would like to push that forward.

“That’s kind of the notion. It’s really not much more developed than that.”