Page 1093 – RTO Insider

May 31, 2020

Online Protesters Reject NY Gas Supply Plans

More than 130 New Yorkers gathered in an online forum Thursday for a “people’s hearing” organized by nearly a dozen environmental groups to protest the possibility of National Grid increasing the state’s supply of natural gas by adding vaporizing capacity, trucking in compressed natural gas and other measures.

NY Gas Protesters — Michaela Ciovacco, NYCP

“This people’s hearing marks an unprecedented coming together of campaigns and minds to tackle getting off fracked gas and moving to renewables, first by focusing on the upcoming June 11 decision by the [New York] Public Service Commission on National Grid’s plan to meet downstate energy demand,” said Michaela Ciovacco of New Yorkers for Clean Power (NYCP).

The group helped organize the event as a member of Renewable Heat Now, along with Sane Energy Project, Alliance for a Green Economy, Mothers Out Front, Sierra Club, Food & Water Action, NY Renews, Stop the Williams Pipeline Coalition, Heatsmart Tompkins and No North Brooklyn Pipeline.

New Jersey and New York regulators two weeks earlier denied permits for the Williams pipeline, also known as the Northeast Supply Enhancement (NESE) project, which would have carried natural gas from Pennsylvania across New York Harbor into the Rockaways, Queens.

“Neither the utility nor the Public Service Commission have scheduled a public hearing, so that’s why we came together,” Ciovacco said.

The organizers claimed that any increase in fossil fuel usage would violate the spirit and the letter of the state’s Climate Leadership and Community Protection Act, signed into law last July. It mandates that 70% of the state’s electricity come from renewable resources by 2030 and that generation be 100% carbon-free by 2040. (See Cuomo Sets New York’s Green Goals for 2020.)

Conflicting State Policies

National Grid spokesperson Karen Young told RTO Insider that a May 8 press release detailed how the company has been fulfilling its 2019 agreement with the PSC to propose long-term solutions for downstate gas supply and demand.

The company’s “no-infrastructure” option includes reducing gas demand through incremental energy efficiency measures, demand response and electrification.

The company this past winter and spring held six public meetings attended by more than 800 people, and altogether more than 7,500 public comments have been filed with the PSC.

National Grid non-gas proposal | *National Grid*

National Grid found itself at odds with Gov. Andrew Cuomo last November when he criticized a company moratorium on new gas hook-ups that the company attributed to supply concerns. Cuomo issued a letter demanding that its gas subsidiaries connect all customers for whom it had denied service under the moratorium or he would seek “to revoke National Grid’s certificate to operate its downstate gas franchise.” (See National Grid Vows to Expand NY Gas Service.)

PSC Chair John B. Rhodes on Oct. 11 had signed an order forcing National Grid subsidiaries Brooklyn Union Gas (KEDNY) and KeySpan Gas East (KEDLI) to connect 1,100 of 3,300 customers that had been denied natural gas service connections (Case 19-G-0678). KEDNY has approximately 1.2 million customers, and KEDLI has 590,000 customers on Long Island.

Brooklyn resident Jackie Weisberg addressed her comments during the online protest to Cuomo: “I oppose the National Grid fracked gas proposal because these pipelines are like the COVID-19 virus. They are insidiously infecting our communities. Selling us the so-called benefits of fracked gas is not what we need now, or ever. They have no business continuing the work in North Brooklyn [on the Metropolitan Natural Gas Reliability Project], and they are opposed in Connecticut and elsewhere.”

Young said “the Metropolitan Natural Gas Reliability Project is a system integrity project, it’s not one of the long-term capacity solutions — it does not bring additional supply to New York.”

Eyes of the PSC

In its Nov. 26, 2019, agreement with National Grid, the PSC mandated that an independent monitor submit quarterly reports to keep it apprised of the company’s progress in finding ways to provide gas service to all its customers in downstate New York.

The monitor’s third report, filed May 26, said that it attended all the public meetings and afterward began “monitoring the key executive meetings conducted internally at National Grid to address its compliance.”

In assessing the company’s development of long-term solutions, the report said it reviewed implementation of energy efficiency and demand response and “makes no formal findings or recommendations but provides observations regarding National Grid’s progress and positions.”

The monitor highlighted National Grid in April having hired Ernst & Young to review the company’s “development of natural gas demand scenarios and the identification and selection of options to meet demand.”

National Grid’s analysis turns on a design day standard, currently a 24-hour period with an average temperature of 0 degrees Fahrenheit in Central Park. The last design day was in 1934, and many public comments questioned the suitability of that standard today, the monitor said.

“To illustrate the point, National Grid has determined that the 24-hour period with the coldest average temperature in Central Park over the last 30 years was approximately 4 degrees F and took place in 1994,” the report said.

The monitor faulted National Grid for being too conservative on the one hand and too extreme on the other for assuming the increased reliance on compressed natural gas trucking through 2035, despite the practice raising “risk, cost and reliability questions.”

“Based on forecast figures provided by National Grid to the monitor, several more middle-ground approaches … indicate possible opportunities to move forward that are less stark than simply choosing between NESE or the no-infrastructure options,” the monitor said.

It also said that the company is not fully accounting for the reduced demand impact from the current pandemic, despite its own reporting that the reduced demand added a year to the predicted time when demand will exceed supply, to the winter of 2022/23.

May 31, 2020

Price Tag Rising for MTEP 20

The 2020 MISO Transmission Expansion Plan (MTEP 20) is shaping up to become one of the RTO’s most expensive ever.

Being developed virtually with stakeholders because of COVID-19 measures, the plan so far contains 510 proposed projects at a combined $4.06 billion, the priciest since MISO’s 2011 multi-value project portfolio. If approved by the RTO’s Board of Directors in December, MTEP 20 will best last year’s plan, which rang in with 480 projects at $4 billion. (See MISO Board OKs $4 Billion MTEP 19.)

Broken down, the transmission investment contains:

149 reliability-related projects at nearly $1.1 billion;
133 age- and condition-related upgrades at $1.05 billion;
77 baseline reliability projects at $783 million;
88 generator interconnection projects at $512 million;
55 projects necessary to accommodate load growth at $606 million; and
eight projects to be built for other local needs at $26 million.

Of those, MISO South accounts for 47 project proposals valued at $750 million.

Stakeholders at subregional planning meetings last week wondered whether some load-growth projects may be scaled back or withdrawn as the catastrophic economic impact of the COVID-19 pandemic continues to play out.

MISO Senior Manager of Expansion Planning Edin Habibovic said transmission owners might revise some projects based on COVID-19 effects, adding that the RTO will have more information on individual load-growth projects during a final round of subregional planning meetings in August. He said discussions over why some load-growth projects drop out likely won’t be disclosed publicly.

Ameren Illinois and Entergy Texas have so far submitted some of the costliest MTEP 20 projects, with the former planning four projects between $74 million and $91 million for reliability and age and condition needs, while the latter is tendering three projects between $65 million and $77 million in response to load growth in its territory.

MISO said it will test one of Ameren’s reliability project submissions — the 345-kV New Holland NW-Neoga South line rebuild in central Illinois — for economic benefits that might allow it to be cost-shared as a market efficiency project.

Altogether, Ameren proposed 152 new projects at an estimated $1.4 billion in its Illinois and Missouri service areas.

Some stakeholders asked why Ameren was suddenly making such big investments in transmission.

MISO expansion planning team member Scott Goodwin said Ameren is this year using a three- to five-year outlook on transmission projects instead of an annual planning horizon. Senior Manager of Expansion Planning Thompson Adu also said MISO has been coordinating with Ameren on issues that require transmission upgrades.

“We make sure we agree with the projects and justifications that they have given to us,” Adu said.

Stakeholders also asked if MISO performs any research to confirm the necessity of TOs’ age and condition projects.

Adu said TOs must justify those projects to MISO, but not all of them provide photos or engineering analyses.

No Midwest-South Tx Solution this Year

MTEP 20 will not contain a long-awaited transmission upgrade to secure more transfer capability on the Midwest-South subregional transmission constraint, stakeholders also learned.

David Severson, a MISO economic studies engineer, said that while there were a “couple promising project candidates,” the RTO will not recommend any Midwest-South transmission projects to the board this year.

Last year, MISO received and screened 35 project ideas to reduce dependence on its Midwest-South transfer constraint. Nine projects passed an initial screening, with three of those showing the required 1:1 or better cost-benefit ratio. (See MISO Floats New Option for Midwest-South Constraint.)

Missouri Public Service Commission economist Adam McKinnie asked why MISO planners don’t submit one of the three project finalists for consideration in the 2020 cycle of the RTO’s and coordinated system plan with SPP, developed to identify potential interregional economic transmission projects.

“I’m waiting for a good reason to hold off on a good solution for another year,” McKinnie said. The transfer limit study has been ongoing since the MTEP 19 cycle.

“We can use the project candidates for a really good starting point in the future,” Severson said. “Further study efforts under an expanded scope would be better served under MTEP 21 future assumptions and models.” MISO is currently redoing its 20-year futures assumptions to factor increased renewable generation and zero-carbon goals in time for the 2021 cycle of transmission planning.

Some stakeholders have criticized the study, saying that MISO focused too narrowly on only increasing the existing contract path capacity and not on a potentially more beneficial increase in physical transfer capability located somewhere else between the Midwest and South regions.

North Study Extends into 2021

Meanwhile, results are pending on MISO’s other special MTEP 20 study on the North Region economic transfer. The study evaluates transfer limitations caused by non-thermal constraints between the renewable-rich northwestern portions of the footprint and load centers in the Upper Midwest. MISO said it’s studying wind generation transfers from the Dakotas, Minnesota and Iowa to Wisconsin and Illinois.

That study will also extend into MTEP 21. MISO economic planner Ryan Hay said that while the study is largely academic, possible transmission projects could be identified and submitted in MTEP 21.

MISO has said the study is the first of its kind and will serve to develop a template for identifying and incorporating non-thermal transmission limits into its production cost analyses. Currently, MISO’s typical economic studies don’t consider non-thermal operational limits. (See MWEX Study Could Elicit New Tx Planning for MISO.)

May 31, 2020February 18, 2025

Exelon, FE Ask PJM to Tighten Sector Selection Process

Two incumbent transmission owners have called on PJM to take a more active role in policing stakeholder sector selections after the disclosure that LS Power had an affiliate improperly voting in the RTO’s senior committees.

“Generally, we think that PJM’s ruleset is a little lax, and some greater oversight of the process may be warranted,” Sharon Midgley, Exelon’s director of wholesale development, said during the Stakeholder Process Forum on May 26.

Exelon had previously raised questions about the propriety of two LS Power subsidiaries, West Deptford Energy and Riverside Generating, voting at the Jan. 23 Members Committee meeting in support of an LS Power resolution. The resolution, which was approved by the MC, objected to a Tariff attachment filed by the TOs to create a new confidential process to mitigate critical infrastructure on NERC’s CIP-014-2 list. FERC OKs PJM TOs’ Critical Tx Process.)

During PJM’s Annual Meeting on May 4, Dave Anders, director of stakeholder affairs, said the RTO had determined that the two companies are under common control and that West Deptford has been recategorized as an affiliate of Riverside, which is listed as the “parent” for 15 members in the Generation Owner, TO and Other Supplier sectors.

Sharon Midgley, Exelon | © RTO Insider

Midgley said LS Power “had been voting with two affiliates at the MRC and MC for many years.”

An LS Power spokesman said Friday that “when notified of a challenge, LS Power cooperated with PJM to provide supporting information, but some of the additional information requested could not be provided prior to the PJM Annual Meeting, when PJM took action. LS Power has decided not to challenge PJM’s decision.” The company declined to comment further.

Under PJM rules, companies with multiple members are entitled to a vote for each of them at lower committees. But they only get one vote at the MC and Markets and Reliability Committee, where votes are sector weighted.

Those rules meant that Pepco Holdings Inc., which had been a strong voice for consumers within PJM as a member of the Electric Distributor sector, lost its independence and its MRC and MC votes when it was acquired by Exelon in 2016. Exelon Business Services, the parent for Exelon’s 14 affiliates, votes in the TO sector. (See Pepco to Lose its PJM Voice; Consumers Lose Frequent Ally.)

A 2017 study by the University of Pennsylvania’s Kleinman Center for Energy Policy found that generation and transmission owners with multiple affiliates can dominate the voting at PJM’s lower committees on proposed solutions. The power dynamic is reversed during votes at the MRC and MC, the report said, because sector-weighted voting often results in buyer-side stakeholders (the Electric Distributor sector and End-Use Customer sectors) exercising veto power over proposals resulting from the lower committees. (See Can RTO Stakeholders Find Consensus on Big Issues?)

Annual Sector Certification

At the May 26 forum, Midgley noted that PJM members are required to recertify or make changes to their sector assignments annually, with changes announced at the Annual Meeting. After sector changes are announced, stakeholders have 30 days to request PJM to investigate any questionable sector selections.

Midgley said that before this year’s Annual Meeting, Exelon identified a member of American Municipal Power attempting to join the TO sector “when they weren’t qualified to do so.” Midgley declined to identify the company.

AMP votes at the senior committees as a member of the Electric Distributor sector, although it has affiliates in the TO and Other Supplier sectors. “That was certainly concerning to us,” Midgley said.

Under section 8.1.2 of the Operating Agreement, companies considered a “related party” of a generation and transmission cooperative (i.e., one of its distribution cooperative members) or a joint municipal agency (joint agency members) are required to vote in the Electric Distributor sector.

Lisa McAlister, AMP’s general counsel for regulatory affairs, said the company learned of the issue after being contacted by RTO Insider for comment Friday.

“From a conversation this morning with PJM … we learned that one of our members was unaware of the related parties sector limitation and mistakenly requested membership in the TO sector, since they are a transmission owner. PJM contacted our member and the error was rectified,” McAlister said. “PJM administers its governing documents and quickly and correctly did so here. There was nothing nefarious about the member request, and we are uncertain as to Sharon’s concern.”

Rule Changes?

Midgley said PJM should consider whether members should be able to review proposed sector changes before they are implemented and if members challenged on their sector change should be required to vote in their old sector until the challenge is resolved by the RTO. She said existing rules allow members to vote in their new sector until a challenge is resolved, a process that can take up to three months to determine.

Exelon would also like a process to examine incorrect sector selections at any time of the year and to allow members to challenge sector selections rather than just during the annual review process, Midgley said. “We think this is a fertile ground for discussion.”

FirstEnergy’s Jim Benchek said his company also would like PJM to take a greater role in overseeing the process. Benchek said the “know your customer” procedures that came out of the special report on the GreenHat Energy default should be implemented by PJM regarding sector selections.

Anders said the RTO is implementing updates to the member onboarding process and know-your-customer efforts as a result of actions taken by the Financial Risk Mitigation Senior Task Force. Anders said some of the issues deal directly with sector selection, and PJM may formulate a report to present to stakeholders later this summer on some of the changes.

Midgley said she was “happy to hear this is on [PJM’s] radar screen.”

Susan Bruce, representing the PJM Industrial Customer Coalition, said her members would be more comfortable having the RTO rather than stakeholders look at “individual business activities” of members, citing confidentiality issues.

20 Sector Changes

During this year’s Annual Meeting, PJM announced that 20 stakeholders had changed sectors, more than double the number of sector selection changes in recent years. For comparison, five sector changes were announced at the Annual Meeting in 2019, six changes in 2018 and eight in 2017.

PJM spokesman Jeff Shields told RTO Insider that “there doesn’t appear to be much out of the ordinary” in the sector changes.

PJM announced at the Members Committee meeting May 4 that these members have updated their sector selection. | PJM

“These new sector classifications reflect changes in corporate structures or the natural evolution of businesses within PJM,” Shields said. “The decisions to make these changes are up to the individual members, in accordance with the Operating Agreement.”

Several PJM stakeholders who changed sectors in May were contacted to determine what prompted their moves.

FirstEnergy’s The Illuminating Co. moved from the TO sector to the Electric Distributor sector. Jennifer Young, manager of external communications for FirstEnergy, said the sector change reflected that the subsidiary does not own or operate transmission assets.

Young said FirstEnergy’s transmission assets in Ohio are owned by another of the company’s subsidiaries, American Transmission Systems Inc.

“The sector change was not prompted by any changes to asset ownership, but rather just to better reflect the type of operations performed by The Illuminating Co.,” Young said.

The Northern Illinois Municipal Power Agency (NIMPA) moved from the Electric Distributor sector to the Generation Owner sector. Gary Holm, president of NIMPA, said the company has been filing as a Generation Owner since 2018 after filing as an Electric Distributor in 2016 and 2017.

Holm said he received an inquiry from PJM in early May about the sector selection, and he informed the RTO that the company had been filing as a Generation Owner since 2018 and wished to be filed in that sector.

“I cannot comment on any change in sector status because, according to our records, our status has remained constant since 2018,” Holm said.

CPV Three Rivers, an affiliate of CPV Power Holdings, updated its sector from Generation Owner to Other Supplier. Tom Rumsey, CPV’s senior vice president of external and regulatory affairs, said to qualify as a Generation Owner, an entity must have cleared a Base Residual Auction or have signed an interconnection service agreement, which Three Rivers has not done.

Rumsey said that when CPV Three Rivers’ membership application was originally approved, the company was told they were being placed in the Other Supplier sector, but they were later notified by PJM that they had been placed in the Generation Owner sector.

“We both agreed that the project should really be in the Other Supplier sector until the project achieves either of those milestones,” Rumsey said.

Energy Harbor, which emerged from the bankruptcy of FirstEnergy Solutions, switched from the TO to the Generation Owner sector, reflecting its separation from former parent FirstEnergy.

May 31, 2020

Texas RE Board Briefs: May 27, 2020

Texas Public Utility Commission Chair DeAnn Walker last week took advantage of a NERC trustee’s presence at a virtual meeting to plead for ERCOT representation on the ERO’s board.

Texas Reliability Entity — PUC Chair DeAnn Walker in 2019 | © *ERO Insider*

“I’m not going to surprise anyone on the board when I say what I’m about to say,” Walker said, following NERC Trustee Suzanne Keenan’s introduction during the Texas Reliability Entity Board of Directors’ meeting Wednesday. “I feel very strongly that NERC needs to consider having a member on the board from the ERCOT region that understands this interconnection,” echoing comments she made during the Texas RE board’s December meeting. (See “Walker Raises Concerns with NERC Representation,” Texas Reliability Entity Briefs: Dec. 11, 2019.)

Keenan, in her third year on the 11-member independent board, was diplomatic in her response.

“Thanks for sharing that with me,” she said. “I am on the [Nominating] Committee this year, so I will definitely take your comments back.”

Texas RE board Chair Fred Day backed up Walker, saying, “I think I speak for the entire board … we all feel that way. It’s time we were represented on the board.”

NERC’s Compliance and Certification Committee, which advises the trustees on all facets of the ERO’s compliance monitoring and enforcement program, has revised its charter to eliminate six regionally allocated seats — one for each regional entity — and replace them with six at-large seats.

Staff Adjust Well to Working Remotely

Texas RE CEO Lane Lanford said some staff could be returning to the office as soon as July 6 but noted the date has already been moved three times.

“July 6 is just another date,” he said.

Lanford said those staffers that return to the office would do so on a voluntary basis, where they will find a different workspace with signage, one-way “streets” through the cubicles and social distance requirements at the coffee machines. The Texas RE may not hold in-person meetings until 2021, though the final decision hasn’t been made.

“We’re pretty good working this way,” Lanford said. “Two years ago, when he started practicing [working remotely], I was wondering what we would ever do taking this much time off. We haven’t had too many bumps in the road.”

He gave kudos to IT staff, saying they were able to improve remote connectivity on the fly.

Day, who is serving his last year on the board, also said he was looking forward to some “actual face time” with staff and directors before the year is out.

“Nothing beats being in the same room, talking,” he said. “Socially distancing, of course.”

Board Approves New RDA, Budget

The board unanimously approved a new regional delegation agreement (RDA) with NERC to replace the current agreement, which expires at year-end. The RDA, which was developed with NERC’s legal staff, includes the option for a five-year extension.

NERC plans to file all six REs’ RDAs with FERC for the latter’s approval by the end of June.

The board also approved a 2021 budget of $14.2 million, a 2.8% increase from 2020, and an “unmodified” audit of Texas RE’s 2019 financial statements with no reported findings. Salaries will increase by 3.2%, primarily because of three new compliance positions.

May 31, 2020

NERC Expands Self-logging During Pandemic

NERC and the regional entities have temporarily expanded their self-logging program to allow registered entities to focus on their response to the coronavirus pandemic.

The self-logging program was introduced in 2015 and allows utilities, with permission of their regional entities, to log instances of potential noncompliance with NERC reliability standards that pose minimal risk to the bulk power system for future review by the ERO Enterprise, rather than submitting a self-report. Noncompliance events logged in this manner are typically resolved as compliance exceptions, which are not included in a registered entity’s compliance history for penalty purposes.

According to the guidance released on Thursday, all registered entities — regardless of whether they are already part of the program — will now be allowed to self-log instances of noncompliance that pose either a minimal or moderate risk to the BPS, as long as the noncompliance is because of “actions to address coronavirus impacts [that] disrupt, complicate or otherwise alter the normal course of business operations.”

NERC has posted a logging spreadsheet template on its website for its compliance monitoring and enforcement program (CMEP). This form should be used by all registered entities for coronavirus-related noncompliance logging, including those that are already part of the self-logging program. Utilities that have not already registered for self-logging will not be entitled to do so for noncompliance instances that are not pandemic-related and will not be considered enrolled in the program following the expiration of the guidance on Sept. 30.

NERC Self-logging — NERC headquarters in Atlanta | © *ERO Insider*

“This expansion allows [registered entities] to focus their immediate efforts and resources on maintaining the safety of their workforce and communities,” NERC said in a statement. “Under this temporary expansion … potential noncompliance related to coronavirus impacts and logged consistently with this guidance is expected to be resolved without further action.”

NERC and the REs, as well as FERC, will review registered entities’ logs at least once each month. Registered entities are required to maintain evidence related to noncompliance incidents for 18 months from the date the logs are submitted to their REs.

NERC Pushes Regulatory Relief

The expansion of the self-logging program is in keeping with several previous moves to ease compliance burdens for utilities dealing with the COVID-19 outbreak. In March, NERC and FERC announced they would use “regulatory discretion” to address difficulties registered entities may have in the following categories:

Inability to obtain and maintain personnel certification for the period of March 1 through Dec. 31;
Failure to perform periodic actions required by reliability standards between March 1 and July 31; and
On-site activities through at least July 31, including audits and certifications, that would ordinarily be performed by REs. (See FERC, NERC Relax Compliance in Light of COVID-19.)

In addition, FERC agreed in April to defer the implementation of seven reliability standards scheduled to take effect this year. (See FERC Agrees to Defer Standards Implementation.) The commission said the delay was intended to reduce pressure on registered entities to ensure compliance with the new standards while implementing coronavirus response measures.

“We don’t want FERC and NERC to be a burden to industry while we’re in this very constrained operating posture,” NERC CEO Jim Robb told the Member Representatives Committee in April. “[We] want to [be] very clear that our commitment is to work with industry to address these issues together.”

May 29, 2020

CPUC Approves PG&E Bankruptcy Plan

The California Public Utilities Commission unanimously approved Pacific Gas and Electric’s Chapter 11 reorganization plan Thursday but warned it will now have regulatory mechanisms to end the utility’s century-old electric monopoly should it fail to ensure public safety.

Part of the proposed decision approved by the CPUC provides for a detailed six-step process of enforcement and oversight by the commission that could eventually lead to it placing conditions on — or revoking — PG&E’s certificate of public convenience and necessity (CPCN), which grants the utility monopoly status over 70,000 square miles of Northern and Central California, with its 5.4 million customer accounts.

CPUC PG&E Bankruptcy Plan — Commissioner Clifford Rechtschaffen | © *RTO Insider*

“This is the time for a PG&E to emerge from bankruptcy that must be reborn with safety as its top priority,” Commissioner Clifford Rechtschaffen said. “Your future depends on it. There’s nothing more or less than that at stake.”

The CPUC decision also required PG&E to replace most of its board members and upper management, and to link executive compensation to safety performance. The utility agreed to break up its operations into eight regional entities and to allow a commission-appointed observer to report on its progress from inside corporate headquarters.

CPUC President Marybel Batjer said she believed the regulations will drive change at PG&E, but if they don’t, the commission is prepared to take further action.

“This transformed company must move from one that is held tightly in the grip of continual correction, of failures, to one that is a model company that is respected for how it serves its customers and community,” Batjer said.

CPUC President Marybel Batjer | *California State Assembly*

The CPUC’s acceptance of PG&E’s Chapter 11 plan was necessary for it to exit bankruptcy, along with the U.S. Bankruptcy Court’s approval, which could come as soon as next week. (See related story, Improper Email Delays CPUC Vote on PG&E Plan.)

Last year’s Assembly Bill 1054 tasked the CPUC with ensuring that PG&E’s reorganization plan serves the public interest, including “the electrical corporation’s resulting governance structure … in light of [its] safety history, criminal probation, recent financial condition and other factors deemed relevant.”

Government investigations found faulty PG&E equipment started the November 2018 Camp Fire, the deadliest in state history, as well as devastating wildfires in 2017 and 2015 and the San Bruno gas pipeline explosion in 2010.

‘We Need a Public Utility’

The series of catastrophes prompted critics to call for a state takeover of PG&E, especially after the utility filed for bankruptcy protection in January 2019 as it faced massive wildfire liabilities.

Gov. Gavin Newsom was among those who threatened state intervention should the company fail to meet his demands for a new board and management, though he ultimately agreed to PG&E’s Chapter 11 plan with the CPUC’s added conditions.

Dozens of public speakers in Thursday’s hearing repeated calls for a public takeover, telling commissioners that PG&E’s Chapter 11 proposal would not do enough to prevent future wildfires or reform its safety culture. Public comments filled the first two-and-a-half hours of the four-hour voting meeting.

Many speakers said PG&E’s primary mission will remain earning profits and rewarding shareholders, the same behavior that they said led to the fires of 2017 and 2018. In April 2019, federal Judge William Alsup, who is overseeing PG&E’s criminal probation stemming from the San Bruno gas explosion, said the utility paid out $4.5 billion in dividends in recent years while neglecting tree trimming and other line maintenance, resulting in the wildfires.

Charlotte Quinn, with the Democratic Socialists of America, told the commissioners that PG&E needs to be accountable to voters, not shareholders.

“We need a public utility,” Quinn said. “The existing and proposed for-profit model is the cause of fires and explosions, death and destruction and old, unsafe infrastructure. Until the profit motive is removed, the energy grid will remain unsafe for communities, just as it has been proven over and over again.”

Commissioner Martha Guzman Aceves said she shared such concerns but was reassured by a bill in the State Legislature that could provide a means for turning PG&E into a public-benefit corporation called Golden State Energy. The measure, Senate Bill 350, by Sen. Jerry Hill, was scheduled for a hearing Thursday in the Assembly Utilities and Energy Committee.

Statutory authority for replacing PG&E as a for-profit monopoly has been lacking, Guzman Aceves noted.

“Fortunately today, through the governor’s leadership and the legislative leadership, we have Sen. Hill’s bill, SB 350, that will soon provide us as a state with the tools to replace PG&E with a customer-elected public option should they fail,” Guzman Aceves said. “This bill will give ratepayers a genuine alternative. If PG&E fails to provide safe, reliable and affordable energy service, then the commission could petition the court to appoint a receiver or revoke PG&E’s CPCN.”

May 29, 2020

Skeptics Get Last Chance to Sound off on PG&E Plan

Pacific Gas and Electric’s chief financial officer took to the virtual stand in bankruptcy court Thursday to face questions about the “feasibility” and “fairness” of the utility’s reorganization plan for the thousands of victims of wildfires sparked by its equipment.

The second day of the confirmation hearing for the plan once again played out over a Zoom conference call and not in the U.S. Bankruptcy Court in San Francisco, where the utility filed for Chapter 11 in January 2019.

After fire victims last week voted in favor of a PG&E reorganization plan that will leave those victims with a $13.5 billion trust half-funded by utility stock, Thursday’s hearing provided dissenters a final chance to sway the judge against approving that outcome. (See Trial Begins to End PG&E Bankruptcy.)

Tom Tosdal, an attorney representing about 1,000 victims of the 2018 Camp Fire, pressed CFO Jason Wells on the soundness — and justness — of the trust.

Of the nearly 40 classes of claimants in the bankruptcy proceeding, Tosdal noted, only the fire victims were being compensated with stock whose value is tied to PG&E’s future performance — a risk in the face of ongoing wildfire threats that could bring more claims against the utility in the future.

Tosdal said the fire victims were being treated worse than subrogation claimants poised to receive full cash settlements. He said the subrogation class itself consisted of two “types”: insurers that have paid out claims to their customers and PG&E shareholders that purchased subrogation claims against the company before it entered bankruptcy.

PG&E plan skeptics — More than 18,000 structures were destroyed in the Camp Fire of November 2018. | © *RTO Insider*

Tosdal cited the hedge fund Baupost, a PG&E investor that starting in November 2018 bought $6 billion in claims against the utility for 30 to 35 cents on the dollar — prompting an objection from PG&E attorney Theodore Tsekerides.

“I don’t think that’s relevant to any of the discussions of the classification issue — who holds those claims. They are what they are,” Tsekerides said.

“It goes to fairness, your honor,” Tosdal said. U.S. Bankruptcy Judge Dennis Montali allowed Tosdal to proceed.

Tosdal asked Wells if Baupost owned many shares of PG&E common stock.

“They do,” Wells replied.

“And do you understand that Baupost bought those subrogation claims at a discount, meaning less than 100% on the dollar?” Tosdal asked.

“I do,” Wells said.

But Wells demurred when Tosdal then asked if he knew that PG&E investors paid a “substantial discount” in their purchase of company subrogation claims.

“So, when this bankruptcy ends, and the subro class is paid $11 billion cash, those PG&E investors, who purchased subro claims against their own company at a substantial discount, stand to make a big profit, correct?” Tosdal continued.

Tsekerides again objected, saying the issue of the discount is “completely irrelevant” to the issue of confirming the bankruptcy plan. Such claims are traded “all the time” in Chapter 11 cases, he said.

Montali turned to Tosdal: “Why is it helpful for to me to make a determination? It is a fact of life that claims are traded at discounts in lots of companies. Why is it relevant to my determination?”

“Because, your honor, when we started this case, I remember that you told everybody on the record, [in the] first hearing, that the most important group in this case to be taken care of are the fire victims,” Tosdal said. “And instead, what is happening here is that the fire victims are getting stock instead of cash, and the effect of that is to provide investors in this company, who have purchased subrogation claims at a discount, with billions of dollars of profit. That is the reality, whether it’s customary for there to be a second market.”

Montali shut down Tosdal’s argument, sustaining Tsekerides’ second objection.

“The fact that an investor, whether it be Baupost or Joe Blow, bought a claim at a discount has nothing to do with how that person will end up being treated,” the judge said. “Your argument tells me that you or your clients don’t like the plan. But the plan isn’t going to turn on the discount rate that an investor paid or didn’t pay. The fact of the matter is a subrogation creditor who didn’t sell his claim at a discount is going to be treated the same as a speculator who bought another subrogation claim at a discount. It doesn’t matter.”

The question of the “feasibility” of the wildfire victims’ trust was at the heart of questions from Will Abrams, an outspoken victim of the 2017 fires that ravaged California’s wine country and burned out a section of Santa Rosa. Abrams focused on the concern that claims from future wildfires could compromise the value of a trust heavily dependent on the company’s share price.

“Would you agree that more wildfires are a risk to the feasibility of the plan?” Abrams asked Wells.

“The risk of catastrophic fires is something that we’re actively managing,” Wells responded. “The combination of all of the work we’re doing to prevent those fires, as well as the passage of Assembly Bill 1054, create the conditions that would make our plan financially feasible.” Passed by the California legislature last year, AB 1054 establishes a wildfire insurance fund for the state’s utilities. PG&E must exit bankruptcy by June 30 to qualify for coverage under the bill.

Abrams questioned PG&E’s ability to mitigate future wildfire risk, citing its past record and what he called its current lack of preparedness. Wildfires are up 60% in California for the first four months of this year compared with last, according to Gov. Gavin Newsom.

Abrams pointed to recent finding by U.S. Judge William Alsup, who is overseeing PG&E’s criminal probation for causing the 2010 San Bruno pipeline explosion, that the company must quickly improve its safety performance to avoid sparking new wildfires. (See Judge Orders PG&E to Improve Line Inspections.)

Overcoming an objection from Tsekerides, Abrams pressed Wells about the number of C-hooks the company has replaced in its aging transmission network (Wells didn’t know) and how much of its annual vegetation management program it has completed this year (one-third as of the end of the first quarter, Wells said).

While Montali provided Abrams with ample time to argue his points and air his views, the judge also evinced skepticism that he will be swayed by his challenge to the utility’s plan.

“You, for one, don’t have a lot of confidence in PG&E going forward, but that’s not the point,” Montali told Abrams. “I have to see if the Bankruptcy Code has been satisfied, and it gets [to be] more than that, because the governor has to be satisfied; the Public Utilities Commission has to be satisfied. And you may be unsatisfied, but if all of those things come together, I then have to be persuaded that PG&E is not likely to need further reorganization under the bankruptcy laws.”

The California PUC on Thursday voted unanimously to approve PG&E’s bankruptcy plan, a key step in moving the plan forward. (See related story, CPUC Approves PG&E Bankruptcy Plan.)

Confirmation hearings will continue into next week, when the bankruptcy court will listen to legal arguments related to the plan.

May 29, 2020

AEP a Go with $2B North Central Wind Project

American Electric Power on Wednesday said it has received enough regulatory approvals to fully move forward with its 1,485-MW North Central Wind Project in Oklahoma.

AEP will invest about $2 billion in the project, which consists of three wind farms and will serve the company’s Southwestern Electric Power Co. (SWEPCO) and Public Service Company of Oklahoma (PSO) affiliates.

The Louisiana Public Service Commission on Wednesday approved a settlement agreement that authorizes SWEPCO — which serves parts of Louisiana, Texas and Arkansas — to purchase 810 MW of nameplate wind capacity from the project. The PSC’s approval included a “flex-up” option that could increase Louisiana’s allocation of that capacity from 268 MW to an estimated 464 MW if Texas regulators do not approve the project.

AEP says the North Central Wind Project will save SWEPCO customers $30 billion over three years. | *AEP*

The Arkansas Public Service Commission also accepted an option to increase the state’s allocation — from 155 MW to about 268 MW if Texas rejects it — when it approved the project earlier this month. The Texas Public Utility Commission’s agenda for its open meeting Friday does not list the project for consideration.

“This investment is expected to save our customers approximately $3 billion over the next 30 years while supporting economic development in our communities,” AEP CEO Nick Akins said. “We will continue to seek approval to provide a share of this renewable energy to our SWEPCO customers in Texas, as we believe the projects offer significant benefits to customers across our SWEPCO footprint.”

PSO received final Oklahoma Corporation Commission approval Feb. 20 for 675 MW. FERC has also approved the project.

The three facilities are being developed by Invenergy in north-central Oklahoma. One facility is expected to be completed by the end of 2020, the other two by the end of 2021.

North Central Wind Project’s three wind farms are slated to be online by 2021. | *AEP*

The project replaces the $4.5 billion Wind Catcher Energy Connection. The plan involved a 2-GW wind farm and a 360-mile transmission connection, but it was canceled in 2018 by AEP when the Texas PUC rejected SWEPCO’s attempt to acquire a 70% interest in the project. (See AEP Cancels Wind Catcher Following Texas Rejection.)

AEP’s regulated integrated resource plans call for the addition of more than 8 GW wind and solar energy between 2020 and 2030.

May 29, 2020

PJM End-of-life Proposals Fail at MRC

A proposal to open end-of-life (EOL) transmission projects in PJM to regional planning and competitive bidding was narrowly defeated in a vote at the Markets and Reliability Committee meeting Thursday.

The “joint stakeholders” proposal from American Municipal Power (AMP), Old Dominion Electric Cooperative (ODEC) and others failed with a sector-weighted vote of 3.23 (65%). The proposal needed a sector-weighted vote of 3.33 (66.7%) for passage.

The proposal won support from 100% of the End-Use Customers, 97% of the Electric Distributors and 71% of Generation Owners. But it was opposed by 59% of Other Suppliers and all but two of 14 Transmission Owners.

Transmission owners would have been required to notify PJM and stakeholders of any facility nearing the end of its life at least six years before its retirement date so that the project could be included in five-year planning models and potentially opened to competitive bidding. It would also modify the supplemental project definition to exclude EOL projects, which would become a new category of regionally planned projects.

A proposal by PJM also failed with a sector-weighted vote of 1.77 (36%) at the MRC.

Despite failing at the MRC, supporters of the joint stakeholders proposal unsuccessfully attempted to bring it to a vote at the Members Committee meeting in the afternoon after Chair Steve Lieberman, of AMP, recused himself from the meeting.

PJM end-of-life — Number of baseline vs. supplemental projects (2010-2019) | *PJM*

After about 90 minutes of parliamentary jousting, the stakeholders called a vote to suspend the rules to allow consideration of their proposal, but the motion fell short of the two-thirds needed with a vote of 3.08 (62%).

ODEC’s Mark Ringhausen, who presented the joint stakeholder package, said it would allow for Order 1000 competition in EOL projects that would ultimately lead to lower costs for ratepayers.

Ringhausen highlighted the TOs’ May 7 notification that they were considering a Federal Power Act Section 205 filing to amend the Tariff as an alternative to the proposals under consideration. Ringhausen said the TO filing at FERC after June 8 would be similar to the PJM proposal, which had “almost zero transparency,” giving the TOs control over most of the future transmission planning.

Dave Souder, PJM’s senior director of system planning, presented the RTO’s package, which would have required TOs to have a formal program for EOL determinations and to identify potential EOL projects five years in advance. Projects that “overlap” with RTEP violations would be included in a competitive window seeking regional solutions.

PJM cited language in the Consolidated Transmission Owners Agreement (CTOA) that allowed TOs to retain the authority to “build, finance, own, acquire, sell, dispose, retire, merge or otherwise transfer or convey all or any part of its assets, including any transmission facilities.” The RTO also said its role was limited by two FERC rulings involving ‘Asset Management’ not Subject to Order 890, FERC Rules.)

“At the end of the day, we’re going to have to agree to disagree,” Ringhausen said of the stakeholders’ insistence that their proposal complies with the CTOA and the PJM Tariff. “Hopefully, we can get this in front of FERC and make them look at it and say what the right outcome should be here for this process.”

Mike Gahimer of the Indiana Office of Utility Consumer Counselor said PJM “misrepresented” the FERC orders. In the order involving Southern California Edison, Gahimer said, FERC stressed the limited scope of asset management as “looking at components, not entire substations or transmission lines for replacement.”

Gahimer said the joint stakeholder proposal didn’t involve components, but rather lines and substations. “I don’t think anyone, including the most biased among us, would claim that the projects at issue here are day-to-day projects,” he said.

AMP’s Ed Tatum said that with the amount of transmission infrastructure that’s going to have to be replaced in the next decade, careful planning is going to be needed. He said PJM’s expertise is essential to ensure that the planning for the grid of the future is simply not rebuilding the transmission system of the past. He fears the future of transmission planning will be moved out of the jurisdiction of PJM and back to the TOs without coming up with compromises.

“That’s a great concern from the standpoint of those who believe transmission and an independent transmission planner is a cornerstone to competitive markets,” Tatum said. “We think that PJM should be the independent planner. We think they bring value from a more holistic look.”

Thursday’s votes are unlikely to bring an end to the billion-dollar debate over control of EOL projects.

The TOs have scheduled a webinar from 2 to 4 p.m. Monday to discuss their potential Attachment M-3 filing. They could file the attachment after the 30-day comment period expires June 8.

Supporters of the joint stakeholders proposal could file a complaint with FERC contending the current procedures are not just and reasonable.

May 29, 2020

NYISO Management Committee Briefs: May 27, 2020

NYISO has suspended the sequestration of its control room operators but is in no hurry to bring its other staff back to ISO offices as New York begins its recovery from the coronavirus pandemic, CEO Rich Dewey told the Management Committee on Wednesday.

The ISO ended sequestration for its Krey Boulevard control center operators on May 4 and that for Carman Road two weeks later, Dewey said. “We think we’re in a reasonable posture to suspend the sequestration of those staff members,” he said, adding that the ISO is prepared to resume sequestration if there is a resurgence of infections in the region.

For now, Carman Road staff are handling the day shift, with Krey Boulevard working nights.

Other NYISO staff are “almost exclusively” continuing to work from home while the ISO tracks the state’s reopening plans.

Although the ISO does have return-to-office plans, Dewey said it will be “conservative” in implementing them. “There’s no particular schedule for when we will start phasing people back into the office,” he said. With telework “working pretty well … we’re not going to be in a rush to change that posture.”

Dewey said the joint Board of Directors/Management Committee meeting scheduled for June 15-16 at the Sagamore Resort on Lake George has been converted to a virtual session. Like past in-person gatherings, the meetings will include both general sessions involving all attendees, and breakouts with individual board members and about 10 stakeholders.

“It’s very important for our board members to get feedback from market participants,” Dewey said. “I think we’ve demonstrated that the technology is quite capable. … We won’t have the normal social interaction, but we’ll do the best we can under the circumstances.”

The topics will include the “Grid in Transition” and “Navigating Uncharted Territory,” which will explore post-pandemic economic changes that may impact the sector.

Summer Capacity Assessment

NYISO’s baseline analysis shows a 1,721-MW capacity margin surplus for the summer peak in 2020, a drop of 506 MW from 2019, said Wes Yeomans, vice president of operations.

The 90th percentile forecast shows a 193-MW shortfall, a decrease of 616 MW from last year. Such extreme conditions might require the ISO to either tap its 2,620 MW of operating reserves or call on emergency operating procedures, including voltage reductions, emergency purchases and voluntary load reductions, for up to 3,080 MW.

The summer assessment shows 2,273 MW in generation deactivations, including the state’s last two coal-fired plants (the 155-MW Cayuga Unit 1 and the 655-MW Somerset plant) and the retirement of Unit 2 of the Indian Point nuclear plant (1,299 MW), which shut down at the end of April.

The ISO has one new generating asset, the 1,177-MW Cricket Valley combined cycle plant in Dover, N.Y.

60-minute Rule for Energy Storage

The Management Committee approved changes to section 4.4.3.1.1 of the Services Tariff to only award energy storage resources (ESRs) energy schedules that are sustainable for at least 60 minutes during a reserve pick-up (RPU) event.

The change was prompted by concern that during an RPU, real-time dispatch may award a larger energy schedule than an ESR can sustain for 60 minutes, as required by the Northeast Power Coordinating Council.

This can occur because the real-time dispatch/corrective action mode used to perform an RPU must issue updated schedules very quickly and thus only looks out 10 minutes.