Page 1080 – RTO Insider

July 5, 2020

NWPP RA Effort Quickly Ramping Up

Northwest Power Pool (NWPP) members last week discussed a proposed Western resource adequacy program that would create a “binding” capacity mechanism for summer and winter but be able to change course if peak loads shift to other seasons in the face of a changing resource mix.

NWPP formally kicked off the RA effort in April in response to mounting evidence that the West could face capacity deficits as early as this year, raising the risk that load-serving entities could inadvertently draw on the same resources for RA as fossil fuel generators retire and the region increasingly relies on intermittent renewables. (See NWPP Planning Western Resource Adequacy Program.)

While still in its early stages, the RA program is proceeding apace after the NWPP stakeholder group spearheading the effort outlined its initial concepts just two months ago. (See NWPP Details Proposed Reliability Program.) Eighteen NWPP members spanning nine U.S. states and one Canadian province have already signed on to the effort, with three additional entities expressing interest in joining, NWPP President Frank Afranji told ERO Insider.

Speaking during a webinar Thursday, Afranji said that NWPP’s RA group has already completed “Phase 2A” of the initiative — the preliminary design — and is now advancing to the detailed design work of “Phase 2B.”

Northwest Power Pool — NWPP says it’s now entering Phase 2B of it RA program development. | *NWPP*

Implementation of a “nonbinding” RA program (Stage 1 of Phase 3) is slated for next year, followed by the rollout of progressively comprehensive Stage 2 and 3 “binding” program — which would require participating LSEs to demonstrate RA in advance and enforce penalties for noncompliance — heading into 2024.

“The implementation phase begins in 2021; however, we have not put out specific dates for the different stages in this phase because the timeline for implementation is still preliminary at this point. I anticipate, as these dates become more certain, we’ll have more information to share at a future public webinar,” Lea Fisher, Public Generating Pool senior policy analyst, said in an email.

“Even when we move into the implementation phase, the program is going to be designed to be very dynamic,” RA group member Gregg Carrington, Chelan County (Wash.) Public Utility District’s managing director of energy resources, said during the webinar.

“We’re going to be able to learn as we go, and it’s going to be continuous improvement,” Carrington said. “To the extent that we discover things that work for us, we’ll keep them, and to the extent we find things that don’t work, we’ll make changes as we go.”

‘Refining as We Go’

NWPP’s current proposal envisions a Stage 1 nonbinding, no-penalty program that asks participants to offer “forward showings” of resource adequacy and availability from participants seven months in advance of the summer (June to September) and winter (November to March) seasons.

“This would be an opportunity to gain experience with the program administrator and submit data, [and] certify all the resources,” said RA group member Joel Cook, Bonneville Power Administration’s senior vice president of power services. “That data would be available to all the participants. We’d have a multilateral agreement between the program administrator and each of the participants to establish requirements.”

The absence of enforcement and penalties will likely exempt Stage 1 of the program from FERC oversight, Cook said.

Stage 2 would introduce a more stringent requirement in which participants must demonstrate to the RA program administrator that they have sufficient resources to meet required metrics for the binding season seven months ahead of the operational timeline.

“An inability to meet showing requirements would result in a penalty or other consequences, and enforceability of the provisions and penalties for noncompliance would likely make the program, at this point, FERC-jurisdictional,” Cook said.

Stage 3 would extend the depth of the RA program by creating a pool of resources for participants to buy and sell for each season’s operational timeline, Cook said.

“The details would be developed with the [NWPP] program developer, so we have a lot of work still ahead of us,” he said. “This is intended to mitigate the risk for participants when the spot market is less liquid, and we have entities relying on that spot market to serve some of their resource adequacy needs.”

Alan Comnes, senior director at consulting firm Energy GPS, asked whether seasonal requirements would be broken down into individual months or consist of a single requirement.

“This is a design aspect that we’re going to be refining as we go,” Carrington replied. “SPP, for example, has a summer-binding season. People submit that six months in advance, but then people also submit information as they get closer and closer to the operational time period. Cal-ISO has an annual review of their capacity product, but then they do a true-up on a monthly basis. We have not made a determination whether or not we’d do a monthly true-up.”

Fred Heutte, Northwest Energy Coalition senior policy associate, asked whether NWPP would consider a monthly, rather than seasonal, RA showing.

“My concern is that system conditions vary a great deal within seasons, and a seasonal approach could lead to over-acquisition of RA resources. Also, the gap months between the seasons are a bit problematic. If RA is addressing both coincident peak demand and need for ramping [and] flexibility, then we will have RA needs in all months,” Heutte said.

“The program that we set up was designed to cover what we considered to be the coincidental peak demand,” Carrington responded. “What we did is we took a look at 10 years of records, and we determined exactly the number of peak-hour demands that occurred … and all of them fell within the time periods that we’ve designed right now. If that changes in the future … the program’s going to be set up to be dynamic, and we’ll be able to make adjustments as we move forward as well.”

RA group member Mark Holman, managing director with Powerex, said the group selected summer and winter as the program’s binding seasons because they contain the greatest risk of a capacity shortfall. Northern reaches of the footprint tend to peak in winter, while those farther to the south peak in summer.

“But that doesn’t mean that entities are not planning their systems in the April-May and the October time periods,” Holman said. “And, of course, if you meet your summer and winter season peaks, you’re often going to have resources available in those other periods. I think the thinking is that as we launch this program, we need to address the critical periods of greatest risk.”

But Holman also agreed with Carrington that if stakeholders identify the need for a spring- or fall-binding RA period, “we can certainly move to that in a future year.”

Stage 0

Portland General Electric Senior Director of Power Operations Cathy Kim reviewed how the program would treat resource eligibility, with resources likely required to undergo a registration and certification process.

Kim also noted that many resource-rich Northwest entities sell capacity out of their systems, requiring the future RA program administrator to validate the counting of capacity to prevent “overselling” as it is transferred from one system to another.

She also emphasized that the program would be “technology-agnostic” and consider all resources, including demand response and battery storage in addition to the region’s predominant thermal, hydro and pumped storage generation.

In reviewing the program’s import-export assumptions, Holman pointed out that modeling assumptions of future hourly imports into the NWPP footprint will have a “significant impact” on identifying the critical hours of RA need and the calculations of participants’ regional planning reserve.

He also delved into an important point for a region populated by entities with heavy surplus capacity, explaining that participants that export energy to other regions must demonstrate those exports are drawn from true surpluses and do not in any way contribute to regional planning reserve margins or lean on the RA program.

It is presumed that entities are making those exports from their surplus capability beyond what they are obligated to show as part of the showing component of the program,” he said.

NWPP is proposing that Stage 1 of the program be preceded by a Stage 0 “stopgap” solution in the event of a loss-of-load event before the RA program commences operation. This interim program would allow participants to give and receive RA assistance “on a voluntary basis during high grid stress periods” in summer and winter. “The intent is for the Stage 0 interim solution to be available this summer,” Fisher said.

Holman wrapped up Thursday’s webinar by applauding the level of stakeholder interest in the RA program.

“I’ll just say that it’s really good to see that people are engaged, and that they’re thinking about the same issues that we’re all thinking about, which is how to achieve a resource adequacy program that really achieves two core purposes: ensures reliability and unlocks investment savings through diversity — and we do that in a very efficient manner.”

July 5, 2020

FERC Approves SPP’s 2nd Go at Dropping Z2 Credits

FERC last week approved SPP’s second effort to eliminate revenue credits for sponsored transmission upgrades under Tariff Attachment Z2 and replace them with incremental long-term congestion rights (ILTCRs), effective July 1 (ER20-1687).

The commission in January rejected an earlier attempt to eliminate the revenue credits, giving SPP an opportunity to file a revised proposal that “does not impose a cap that limits the term and potential value of ILTCRs.” (See FERC Order Keeps Z2, Aids EDF’s Sponsored Project.)

The RTO responded in April with a filing that proposed to remove the cap on the amount recoverable through the candidate ILTCRs and revert back to current provisions allowing those ILTCRs a term of at least 10 years and up to 20 years.

The June 30 order was a defeat for renewable developers, who contended that SPP’s proposal would violate FERC’s cost allocation policies because upgrade sponsors — generally wind and solar facilities — would no longer receive direct payments from third parties who benefit from an upgrade. They argued SPP could not remove Z2 credits without trying to replace them with another mechanism “that considers whether others benefit from these directly assigned network upgrades.”

The commission disagreed, saying upgrade sponsors receive ILTCRs as a form of compensation for being directly assigned network upgrade costs. Third-party beneficiaries of incremental network upgrades “will continue to indirectly pay for such upgrades through congestion payments,” it wrote.

“To the extent that an upgrade is utilized at its full capacity in the day-ahead energy market and thus generates congestion rent … a load-serving entity whose power consumption contributes to congestion on the upgraded facility will fund ILTCRs associated with the upgraded facility through its congestion payments,” FERC said.

SPP Z2 credits — Z2 credits for transmission upgrades will soon be a thing of the past for SPP members. | *Apex Clean Energy*

Under Attachment Z2 of SPP’s Tariff, transmission customers that fund network upgrades can be reimbursed through transmission service requests, generator interconnections or upgrades that could not have been honored “but for” the upgrade.

SPP has been trying to replace Z2 credits since 2016, when controversy arose after the grid operator identified eight years of retroactive credits and obligations that had to be resettled after staff failed to apply credits. (See SPP Invoices Lead to Confusion on Z2 Payments.)

In a separate proceeding related to the retroactive Z2 payments, FERC in February denied SPP’s request for a rehearing of a 2019 order that the RTO provide refunds of credit payment obligations (ER16-1341). (See FERC Denies Rehearing in Z2 Remand Order.) SPP and Oklahoma Gas & Electric have appealed the decision to the D.C. Circuit Court of Appeals, where the matter is expected to be set through a briefing process, according to the RTO.

FERC Accepts Generator-replacement Proposal

FERC on June 30 also accepted SPP Tariff revisions that create procedures for expedited replacement of existing generating facilities when the replacement is not a material modification, effective July 1 (ER20-1536).

The commission said SPP’s procedures will avoid duplicative study costs and operational costs that otherwise would occur when the replacement request must proceed through the interconnection study queue process, delaying the addition of more efficient and cost-effective resources. FERC said the proposal will prevent generator owners from losing their existing interconnection service and potentially incurring “significant costs” to obtain replacement service at the same location.

“We find that SPP’s proposal will allow for more efficient use of the transmission system by streamlining the current replacement process,” the commission said.

FERC found SPP’s proposed process complies with Order 2003, which requires public utilities that own or operate transmission to file generator interconnection procedures for facilities with capacity greater than 20 MW. The order provides for pro forma large generator interconnection procedures (LGIP) but allows for variations consistent with or superior to the standard LGIP.

In its April filing, SPP said its proposal will encourage owners of existing facilities to upgrade to newer, more efficient technology.

Multiday Minimum Run Time OK’d

FERC’s Office of Energy Market Regulation on June 30 issued a letter order accepting SPP’s Tariff revisions that allow market-committed resources with a minimum run time extending beyond initial reliability unit commitment or day-ahead commitment periods to be eligible for make-whole payments after their initial commitment period (ER20-1782).

The RTO’s stakeholders approved the change in January. It is intended to minimize potential gaming opportunities identified by the Market Monitoring Unit. (See “Members Pass 12 Revision Requests,” SPP MOPC Briefs: Jan. 14-15, 2020.)

FERC to Examine Roughrider’s Formula Rate

FERC on June 30 also accepted SPP’s Tariff revisions that add a formula rate template and implementation protocols allowing Roughrider Electric Cooperative to recover its annual transmission revenue requirement (ATRR) as a transmission-owning member of the RTO, effective July 1 (ER20-1750).

However, the commission said its preliminary analysis indicates the proposed revisions may be unjust and set them for hearing and settlement judge procedures. Missouri River Energy Services had protested the filing, arguing that it lacked adequate detail about the source of certain construction costs.

Roughrider, embedded in the Integrated System as a Basin Electric Power Cooperative member, joined SPP on April 30 and has been placed in the RTO’s Upper Missouri pricing zone. The North Dakota distribution cooperative serves more than 8,000 members in six counties. It purchases power through Montana’s Upper Missouri Generation & Transmission Cooperative and also sources energy from SPP members Basin Electric Power Cooperative and Western Area Power Administration.

FERC did not suspend and subject Roughrider’s ATRR to refund obligations because the co-op is not within the commission’s jurisdiction under Section 205 of the Federal Power Act. However, it noted that Roughrider voluntary agreed to issue refunds should it change under the hearing and settlement judge process.

July 5, 2020

Panelists Probe Racial Disparities in Energy Industry

Industry experts last week discussed the energy industry’s racial gaps and how to design more equitable energy policies that address the higher bills and bad air quality often faced by the poor.

Diana Hernandez, Columbia University assistant professor of Sociomedical Sciences at the Mailman School of Public Health, said one out of three U.S. households are “energy insecure” — paying a high proportion of their earnings on utility bills, facing disconnection notices or forced to keep their homes at unhealthy temperatures to cut costs.

African Americans and Latinos are most likely to face energy insecurity and often pay more for energy bills, Hernandez said during the June 30 panel discussion, held via Zoom and sponsored by Pecan Street, an Austin, Texas-based electricity data research organization.

Hernandez said “the legacy of segregation” means that marginalized populations live in older, less energy-efficient households and are generally not able to afford new efficient appliances, better insulation or new windows.

The University of California Berkeley’s Energy Institute at Haas in June found that Black households have higher residential energy expenditures than white households across the nation. Researchers said Black renters pay on average $273 more per year than their white counterparts, while Black homeowners pay about $408 more per year than white homeowners.

“They’re paying more, and they’re benefiting less from new energy technologies,” Hernandez said.

“People end up making trade-offs in quality of life for high-energy burdens,” said Dana Harmon, executive director of the Texas Energy Poverty Research Institute. She said that food and clothing are the most common concessions before covering high energy bills.

Hernandez used as an example Lisa Daniels, a 68-year-old Newark, N.J., resident who died in 2018 after Public Service Electric and Gas disconnected her power, leaving her without access to her oxygen mask. Her death prompted New Jersey Gov. Phil Murphy last year to sign a law that bars utilities from shutting off power for 90 days after nonpayment by customers who rely on electric medical devices to survive.

Pecan Street General Counsel and CFO Fisayo Fadelu said disadvantages for communities of color are evident in cities’ infrastructure investments.

“We need to acknowledge that the playing field is not even. Equal investment will not work,” she said.

Fadelu said that while communities of color might not recognize energy justice as a priority, energy efficiency lowers housing costs. The clean energy sector can provide much-needed well-paying jobs, she said, but cities must be willing to invest in those communities to correct racial burdens, she said.

Racial Disparities — Environmental Defense Fund Director of Regulatory and Legislative Affairs John Hall | *Pecan Street*

“Race has been and is the most dominant issue in American politics,” said John Hall, director of regulatory and legislative affairs for the Environmental Defense Fund. “Because racism is such a dominant force in our society, that gives rise to systemic racism. And systemic racism is in every sector and industry.”

Hall said the first step organizations usually take is enacting diversity equity and inclusion plans pertaining to hiring practices, then extending those principles to their contractors.

“Overall, the energy sector, as well as the fossil fuel industry and clean energy sector, have not enacted diversity, equity and inclusion plans,” Hall said. “And as a consequence, they have not afforded communities of color the opportunity to participate.”

Minority communities are more likely to be located near fossil fuel plants and bear the brunt of harmful emissions, Hall said. Employees of color are often barred from blue-collar jobs in energy production, he said, expressing concern the same trend is developing in the clean-energy sector.

“We need all Americans — not most — to make being anti-racist their business,” Hall said.

MISO is one organization that recently recommitted to diverse hiring practices during its June Board of Directors meeting. (See MISO Board Addresses Racism, Social Unrest.) A recent follow-up letter from Board Chair Phyllis Currie and MISO CEO John Bear acknowledged “recent events of horrific mistreatment of the African American community.”

“We view these events as indicative of even broader concerns over systemic racism that unfairly discriminates against human beings throughout this community and many other diverse communities,” Currie and Bear wrote.

“We stand with the African American community,” the letter continued. “It is a community in pain, and we know that to have real empathy, we must do more to listen and learn from their perspectives on systemic racism and long-term disparate treatment.”

Currie and Bear vowed MISO will recruit interns from historically Black and Hispanic colleges and universities.

Pecan Street said it plans to hold additional virtual panel discussions on the energy industry’s racial disparities.

July 5, 2020

Regulatory Setback Doesn’t Stop AEP Wind Project

Texas regulators Thursday rejected their ratepayers’ participation in an American Electric Power wind project for the second time in three years, denying a plan by subsidiary Southwestern Electric Power Co. (SWEPCO) to add 810 MW of wind energy (49737).

The Public Utility Commission’s denial will not affect AEP’s $2 billion North Central Wind Project, comprising three wind farms in Oklahoma that will provide 1,485 MW of capacity. Arkansas, Louisiana and Oklahoma regulators have already approved the project, as has AEP a Go with $2B North Central Wind Project.)

An estimated 464 MW of capacity will now be allocated to SWEPCO’s Louisiana customers and 268 MW to Arkansas customers. SWEPCO sister company Public Service Company of Oklahoma’s (PSO) share will remain at 675 MW. SWEPCO wholesale customers will receive an additional 78 MW.

AEP wind — Invenergy is building the three North Central wind farms. | *Invenergy*

SWEPCO President Malcolm Smoak reiterated that the PUC’s order does not affect North Central’s “full viability.”

“It is disappointing that our customers in East Texas and the Panhandle will not have access to this major wind project, missing the opportunity for long-term cost savings and making it more difficult for businesses, residents and communities to meet their renewable energy goals,” he said in a statement.

AEP says the North Central wind facilities will save its SWEPCO and PSO customers $3 billion over the next 30 years.

The Texas commission rejected that argument in approving administrative law judges’ proposed decision. The ALJs said the North Central wind facilities “will significantly increase SWEPCO’s rate base, with some of the financial risk placed on the customers rather than the shareholders.”

SWEPCO’s request was opposed by most intervening Texas consumer groups. They pointed out that the wind generation is not needed for SWEPCO’s capacity needs. PUC Chair DeAnn Walker agreed, noting the utility is projected to have excess capacity until 2026.

“How this has been laid out is not something that I can go with,” she said.

“There are features of the project that I really like, but if you bring us a project [that benefits consumers], yet all consumer groups are opposed,” Commissioner Arthur D’Andrea said, “it makes it difficult to grant that.”

“It seems like the quantification of benefits … did not become, to me, convincing,” added Commissioner Shelly Botkin.

Invenergy is developing the three wind farms. One is expected to be completed this year, the other two by the end of 2021. SWEPCO and PSO will acquire the facilities upon their completion.

In 2018, the PUC similarly denied SWEPCO’s attempt to acquire a 70% interest in AEP’s proposed $4.5 billion Wind Catcher Energy Connection. AEP canceled the project the day after the commission’s rejection. (See AEP Cancels Wind Catcher Following Texas Rejection.)

July 2, 2020

NERC Opens Comments on SOL Proposals

NERC is requesting comments from stakeholders on changes to several reliability standards proposed by the team updating the requirements for determining and communicating system operating limits (SOLs), as well as on the team’s implementation plan (Project 2015-09).

The posting was approved by NERC’s Standards Committee at its previous meeting in June, with comments being accepted through Aug. 3. (See “SOL, Training Proposals Accepted,” NERC Standards Committee Briefs: June 17, 2020.) Balloting for the standards and implementation plan will be conducted from July 24 through Aug. 3.

Ballot pools will be formed through July 20; NERC announced Wednesday that existing ballot pools will be reopened to allow stakeholders to join if desired.

Range of Standards Affected

The standards posted for comment and balloting include:

CIP-014-3 – Physical Security
FAC-003-5 – Transmission Vegetation Management
FAC-011-4 – System Operating Limits Methodology for the Operations Horizon
FAC-013-3 – Assessment of Transfer Capability for the Near-term Transmission Planning Horizon
FAC-014-3 – Establish and Communicate System Operating Limit
PRC-002-3 – Disturbance Monitoring and Reporting Requirements
PRC-023-5 – Transmission Relay Loadability
PRC-026-2 – Relay Performance During Stable Power Swings
TOP-001-6 – Transmission Operations
IRO-008-3 – Reliability Coordinator Operational Analyses and Real-time Assessments

The standard drafting team’s questions for respondents mainly focus on the updated Facilities Design, Connections, and Maintenance (FAC), Interconnection Reliability Operations and Coordination (IRO) and Transmission Operations (TOP) standards because of the “numerous and significant concerns” raised by industry stakeholders during the SDT’s previous posting in 2018. Specifically, many commenters objected to the use of FAC standards to define SOL exceedances. In response, the team moved SOL determination from FAC-011-4 and FAC-014-3 to IRO-008-3 and TOP-001-6. The revised standards will leave the definition of SOL exceedances to transmission operators and reliability coordinators.

Additional changes to FAC-011, TOP-001 and IRO-008 deal with industry questions over compliance and administrative burdens from the new logging requirements. The SDT is asking stakeholders whether they agree with the “risk-based approach” for identifying and communicating SOL exceedances that is intended to let operators focus on mitigating issues rather than divert resources for reporting them.

The last major question for stakeholders involves the SDT’s decision to drop its proposed FAC-015 standard — which would have addressed criteria for determining SOLs — and move its requirements into FAC-014-3. FAC-015 was originally introduced because of the planned retirement of FAC-010-3 (System operating limits methodology for the planning horizon), but industry feedback convinced the team that FAC-014 would be a better place for the requirements.

Schedule Slips on Scope Expansion

NERC SOL Proposals — Dean LaForest, ISO-NE | © *ERO Insider*

The comment period for Project 2015-09 was originally planned to open in February, after the SDT reported in November that it had resolved most sticking points that had held it back since the 2018 posting, other than those involving logging and communication requirements. (See “Team Expects Feb. Posting on SOL Project,” SOL Project Team Preparing for March Posting.)

One reason the team’s business has taken longer to conclude than expected — according to NERC’s Project Tracking Spreadsheet, it is the oldest standard drafting project still in progress — is its decision to expand its scope beyond its original mandate. This has led to both an increased workload for the team and concern from industry participants about possible overreach.

“Our drafting team was established to modify a succinct set of FAC standards,” SDT Chair Dean LaForest of April Ballot Planned for SOL Standards.)

July 2, 2020

Governor Signs PG&E ‘Plan B’ Takeover Bill

Pacific Gas and Electric said it had completed its bankruptcy restructuring Wednesday, one day after California Gov. Gavin Newsom signed a bill allowing the state to take over the utility if it fails egregiously over time to obey the Public Utilities Commission’s rules.

Those rules, imposed as a condition of the commission’s decision to accept PG&E’s bankruptcy plan in May, required the utility to submit to enhanced oversight and escalating enforcement for safety failures. Repeated and uncorrected problems could let the commission appoint a third-party monitor followed by a receiver, and eventually to rescind PG&E’s license to operate as the monopoly utility for most of Central and Northern California.

PG&E takeover bill — Gov. Gavin Newsom | © *RTO Insider*

If that happens, the newly enacted Senate Bill 350 authorizes the state to seize PG&E through eminent domain and transfer its operations and assets to a nonprofit public benefit corporation called Golden State Energy, created by the legislature and governor.

“The purpose of this division is to ensure that if Pacific Gas and Electric Co. fails to emerge from bankruptcy as a transformed utility, then Golden State Energy is duly empowered to serve in that critical role,” the new law says. “It is the intent of the legislature that Golden State Energy act pursuant to this division only in the event that a transformed utility does not emerge from the bankruptcy or the transformed utility fails to meet its duty to provide safe, reliable and affordable energy services.”

Some critics have contended the CPUC’s six-step process of punishing PG&E would take so long that a takeover won’t happen. Dozens of public speakers urged the commission to yank PG&E’s license immediately prior to its approval of the utility’s reorganization plan May 28.

“We need a public utility,” one that’s not motivated by profits to forgo safety upgrades and maintenance, San Francisco Bay Area resident Charlotte Quinn told commissioners.

Newsom said in a statement Tuesday, however, that his signing of SB 350 means there will be “no more business as usual for PG&E.”

“As we head into wildfire season amid a pandemic, Californians need to have confidence that their utility is focused on customer safety, preventing wildfire[s] … and making critical safety upgrades,” the governor said. “SB 350 marks a critical step in the transformation of PG&E into a utility that is accountable to those it serves.”

The measure authorizes the state to sell bonds to finance the purchase of PG&E. It cleared the State Senate on Monday and went to Newsom for his signature.

Bill author Sen. Jerry Hill (D) has called the measure a “plan B” if PG&E doesn’t undergo the safety transformation it has promised. (See Plan B for PG&E Takeover Moves Forward.)

“As much as we push forward with that change, we must also be prepared to step in should the company not meet its obligations or commitments in the future,” Hill told the State Assembly’s Utilities and Energy Committee last month. “SB 350 is our preparation. I hope it’s unnecessary and that it’s never triggered, but we owe this preparation to the residents of San Bruno and Santa Rosa and Napa and Butte County and Paradise.”

Those communities were devastated by PG&E-caused catastrophes in the past decade.

The Camp Fire, the state’s deadliest and most destructive wildland blaze, wiped out most of the town of Paradise on Nov. 8, 2018, killing 85 residents and destroying more than 14,000 homes. The wine country fires of October 2017 ravaged the city of Santa Rosa and large areas of Napa and Sonoma counties. A gas pipeline explosion in September 2010 killed eight people and destroyed part of a residential neighborhood in San Bruno, a San Francisco suburb.

An estimated $30 billion in liabilities for the fires of 2017 and 2018 caused PG&E to seek bankruptcy protection in January 2019.

‘One Step Closer to Getting Paid’

PG&E said Wednesday it had emerged from that bankruptcy after nearly 18 months by obtaining the debt-and-equity financing it needed to fund $25.5 billion in settlements with fire victims, government agencies, insurance companies and the hedge funds that bought up billions of dollars in insurance subrogation claims.

U.S. Bankruptcy Judge Dennis Montali approved PG&E’s Chapter 11 plan on June 20, less than a day after it pleaded guilty to 84 charges of involuntary manslaughter in the Camp Fire. (See PG&E Sentenced; Bankruptcy Plan Approved.)

“Today’s announcement is significant for PG&E and for the many wildfire victims who are now one step closer to getting paid,” acting CEO Bill Smith said in a news release. Smith replaced former CEO Bill Johnson, who retired Tuesday.

“Compensating these victims fairly and quickly has been our primary goal throughout these proceedings, and I am glad to say that today we funded the fire victim trust for their benefit,” Smith said.

PG&E plans to fund the victims’ trust with $6.85 billion in cash in three installments through 2022 and with stock shares equal to a 22% stake in the utility, the largest electric provider in North America.

The company also said it had seated a mostly new 14-member board of directors and paid its $5 billion contribution to the state’s wildfire insurance fund, created under last year’s Assembly Bill 1054. (See PG&E Names New Board of Directors.)

Under the legal doctrine of “inverse condemnation,” California holds utilities strictly liable for fires sparked by their equipment. The $21 billion fund, to be paid for equally by ratepayers and utilities, provides financial protection against devastating blazes going forward.

July 2, 2020

Tx Incentive NOPR Leaves Many with Sticker Shock

FERC’s proposed new approach to awarding transmission incentives drew some support but also generated much sticker shock among stakeholders, who said it would increase costs in many cases without providing additional benefits (RM20-10).

Wednesday was the deadline for comments on FERC’s March Notice of Proposed Rulemaking that would, among many other things, double the adder for participating in an RTO and shift from awarding benefits based on the risks and challenges of a project to one focused on economic and reliability benefits. (See FERC Proposes Increased Tx Incentives.)

FERC, which gained authority to issue incentives in the Energy Policy Act of 2005, implemented its policy in Order 679 in 2006 and opened a Notice of Inquiry to reconsider the policy in 2019 (PL19-3).

‘But For’ Projects

Alliant Energy and DTE Electric, identifying themselves as “transmission-dependent utilities,” said incentives should only be available for “transmission development that is not otherwise occurring or to accomplish specific policy objectives,” saying bonuses are not needed in MISO’s footprint, which “has experienced robust transmission development over the last 10 years without them.”

The companies said incentives should be reserved for high-risk and high-reward projects such as interregional transmission. “Blanket approval of incentives does little to drive desired behaviors; instead, such actions may encourage overbuild and add unnecessary costs to customers.”

Similarly, the American Council on Renewable Energy (ACORE) said incentives should be limited to projects that prove their proposals “would not be built but for the award of the incentive.”

“FERC explained it has not proposed such a ‘but for’ provision because Congress did not clearly direct the commission to include such a provision. However, Congress did direct FERC to incentivize new transmission capacity if it benefits customers. Awarding ratepayer funds to project applicants that would be built in the absence of an incentive are not being incentivized by the award.”

A coalition of consumer and environmental groups that have opposed transmission projects — including Transource Energy’s Independence Energy Connection project in PJM and Central Maine Power’s New England Clean Energy Connect merchant line — said the commission seemed to ignore the comments in response to its NOI “in favor of proceeding with a predetermined agenda.”

The groups said Congress’ legislation authorizing incentives had a dual purpose of both ensuring reliability and reducing the cost of delivered power by reducing congestion. “As written, the statute clearly intends that the cost of incentives to consumers shall be ameliorated by reduction in their power costs. In practice, the commission’s incentives policy has historically taken liberty with the stated purpose of the statute and congressional intent.”

From ‘Risks and Challenges’ to ‘Benefits’

FERC’s proposal to shift from awards based on “risks and challenges” to one based on “benefits” resulting from the project drew both support and opposition.

ACORE supported the change, saying it would help ensure deployment of energy storage as transmission as well as new technologies. “Dynamic line ratings and other technological innovations can provide quantifiable economic benefits and reduced power costs by increasing the capacity of transmission infrastructure at lower costs than new wire solutions, but these innovations are not properly compensated for their benefits under the current approach.”

Among FERC’s proposals was a 50-basis-point (bp) adder to projects that meet a pre-construction benefit-to-cost ratio in the top 25% of projects examined over a sample period, with another 50 basis points for projects that meet a post-construction b/c ratio in the top 10% of projects.

The commission also proposed up to 50 bp for projects that show reliability benefits through quantitative or qualitative analysis.

The R Street Institute, a free-market advocacy think tank, said that the proposed 100-point economic benefits adder, “on its face, seems absurd, as any project should pass a cost-benefit analysis prior to approval. Increasing ROE [return on equity] for something that should already be happening does not incentivize transmission projects to be more cost effective.”

The American Public Power Association said the ex ante economic benefit adder “would unreasonably grant incentives based on analysis of congestion cost savings that might never materialize, and the ex post economic benefit adder rewards projects that have already been built.”

APPA said any reliability incentive should be limited to the portion of the project investment that is needed to produce reliability benefits above NERC reliability standards. It also said reliability incentives should not be “based on qualitative reliability benefit claims alone.”

The National Association of State Utility Consumer Advocates (NASUCA) said the change “will result in the payment of costly incentives to transmission projects likely to be built anyway, with or without incentives, and thereby serves to increase the cost of transmission projects borne by customers while providing no clear customer benefit.”

“The NOPR fails to provide evidence that the incentives are needed,” said Paul N. Cicio, president of the Industrial Energy Consumers of America, which filed comments jointly with 37 other groups under the name “American Manufacturers.”

“Transmission projects that are needed are getting built,” Cicio said. “Every dollar of financial incentive would be passed onto us, the consumer ratepayer. Given today’s economic uncertainty, this is a terrible time to consider increasing electricity rates on manufacturers, our nation’s job creators.”

Advanced Tech

The Working for Advanced Transmission Technologies (WATT) Coalition and Advanced Energy Economy submitted joint comments noting that FERC has never implemented the requirement in EPAct 2005 that it encourage the deployment of new transmission technologies.

“For all the hundreds, if not thousands, of proceedings on energy market design, significant efficiencies lie untapped in the operation of the physical network hardware,” they said.

The groups proposed “a modest, targeted incentive to support the adoption of advanced transmission technologies like dynamic line ratings, topology optimization, and similar tools that increase the capacity and efficiency of the existing grid.” They said their proposal would fulfill FERC’s statutory obligations.

Transmission Incentive NOPR — | *Burns & McDonnell*

R Street said, “The number of adders that are available to transmission projects is already quite generous and should be examined before handing out more customer dollars for these ventures.” It called FERC’s proposal to replace the current limit on incentives with a 250-basis-point cap on total ROE adders “a good start,” but it said “there needs to be a stop to the layering of incentives, as it is not attracting new and innovative technologies.” It also said the proposed 100-point adder for new technologies is “not enough to retool the transmission system.”

“FERC needs to be … setting up a regulatory paradigm that can usher in new innovations and technology,” R Street said. “Any enhancements to the electric grid need to include more than just ROE incentives; for new technology to be pushed forward, FERC must look to other models to properly incentivize innovation.”

The Energy Storage Association said storage should be eligible for incentives because of its ability to “enhance the flexibility and efficient use” of existing transmission facilities.

“Returns for transmission owners are largely based on allowed rates of return from capital investment. Even if less expensive investments can attain operational capabilities that achieve equal or superior outcomes as a conventional transmission solution, transmission owners would face a reduction in return by undertaking the less expensive investment,” ESA said. “For example, fast-acting energy storage can provide rapid injections pre- or post-contingency events to maintain reliability of the transmission system and reduce congestion on key lines or interfaces. Use of storage in this way can be far less expensive than building redundant transmission conductors, which is the standard way to handle transmission contingencies.”

Doubling RTO Adder

FERC’s proposal to double the adder for participation in an RTO from 50 to 100 basis points attracted much opposition, with some critics saying it should be eliminated altogether.

“What action or decision is influenced by an incentive that rewards a continued payment years after the joining of the RTO?” the Union of Concerned Scientists asked, noting that most RTOs and ISOs already had most of their current members in 2005. “Simply rewarding continued membership seems to provide additional revenue to member utilities without commensurate increase in benefits to consumers,” it said.

“No evidence has been put forth demonstrating that the existing benefits of RTO membership are insufficient incentive for TOs to join and remain in RTOs absent an ROE adder,” the Maryland Public Service Commission said. “The existing 50-bps RTO ROE adder as it stands … provides no incremental benefit to customers. Therefore … the commission’s proposed 100-bps RTO ROE adder [is] simply wholly untenable.”

“The commission’s proposal to double the RTO participation incentive ROE adder in perpetuity will only add costs and provide no discernable benefits to customers who have paid very expensive RTO participation adder for many years,” NASUCA said.

The proposal also drew fire from the California Public Utilities Commission. (See CPUC Calls FERC Tx Incentive Plan ‘Atrocious .’)

But the PJM Transmission Owners sector said the increased incentive is justified because “the risks to transmission owners of RTO membership are significant, such as giving up control of their system and assets to join and participate in RTOs.”

The TOs said, however, that incentives are not sufficient, saying the commission must also “ensure a stable and equitable policy on transmission owners’ ‘base’ return on equity.”

Need for Transmission Planning Reform

The Electricity Consumers Resource Council, filing with the American Chemistry Council and the American Forest & Paper Association, said they understand the need for new transmission but disagree with that incentives “should be — or can be — a key driver of that development.”

“The root cause of underdevelopment, to the extent underdevelopment is pervasive and problematic, is a set of institutional barriers that should be addressed head-on instead of tangentially, expensively and ineffectively via transmission incentives policy,” the groups said. “The appropriate tools available to federal policymakers to address barriers to development include improvements to transmission planning and cost allocation, as well as new legislation from Congress if it chooses to address any additional federal role in transmission siting.”

ACORE also called for changes to transmission planning procedures. “The incorporation of grid optimization and advanced technologies in the planning process, more standard and broad cost allocation, and increased inter-RTO transfer capability will lead to a more robust and efficient electric grid,” it said. “Where possible within its authority, FERC should enhance efforts to streamline transmission siting and enable construction of necessary transmission lines.”

The group cited research from the National Renewable Energy Laboratory that increased transmission development at regional seams could save consumers more than $47 billion and return more than $2.50 for every dollar invested.

ITC also called for a broader review, saying for incentives to proceed “it is necessary to revisit other commission policies and potentially abandon them (e.g., competitive solicitation processes) or reform them (e.g., transmission planning).”

The company said Order 1000’s competitive solicitation processes are “in direct conflict with the commission’s incentives policy” by encouraging TOs to adopt least-cost projects to address transmission needs.

Instead, it said the commission should use a risk-sharing approach similar to that of the New York Public Service Commission for public policy transmission, which gives the developer 20% of cost savings below the targeted cost with the remaining 80% going to consumers. Developers are responsible for 80% of any cost overruns.

UCS noted that the NOPR does not include any incentives for interregional transmission projects.

“Amongst the topics under review in this process, the insufficient attention and lack of incentives for interregional transmission stands out,” the group said. “The commission should acknowledge in this rulemaking that there is a problem when the borders of the ISOs/RTOs create gaps in market-based transfers of energy, increase costs due to congestion, and introduce obstacles and risks to the planning, evaluation and ultimate construction of interregional transmission.”

Eliminate Transco Adder

ITC Holdings said FERC’s proposal to eliminate incentives for standalone transmission companies (transcos) “is premature and based on flawed assumptions.”

“The last decade has been characterized by steady economic growth in tandem with a transformation in the energy sector once thought unimaginable, thus creating an environment that has allowed transcos and vertically integrated utilities alike to make significant investments in transmission infrastructure,” ITC said. “However, the real measure of a transco’s value is better captured in more challenging economic conditions when vertically integrated utilities are required to make difficult choices between investments in generation, distribution and transmission. Indeed, when one looks at the period from 2000 to 2010 — a period that includes the last major recession — transcos far outpaced vertically integrated utilities in terms of transmission investments.”

July 2, 2020

PJM Responds to IMM Report

PJM has responded to the Independent Market Monitor’s annual State of the Market R eport, highlighting five different areas of focus out of hundreds of recommendations.

In its response released Monday, PJM said it met with representatives from Monitoring Analytics, the RTO’s Monitor, on several occasions in the leadup to the March release of the report to discuss areas of prioritization for 2020. Discussions led to prioritizing five different issues out of 213 recommendations contained in the report, including:

a holistic review of the auction revenue rights (ARRs) and financial transmission rights markets design;
five-minute pricing and dispatch;
a capacity market default market seller offer cap;
the future of up-to-congestion transactions; and
energy market power mitigation.

“Some of the recommendations in these areas propose solutions that may require additional analysis by PJM and Monitoring Analytics; stakeholder discussion and vetting; or are recommendations on which PJM and MA have not yet agreed,” PJM said in its response.

PJM IMM Report — PJM categorization of recommendations from the 2019 State of the Market Report | *PJM*

ARR/FTR Market Design

The ARR/FTR products have been a major area of focus for PJM, the Monitor and stakeholders in recent years, the RTO said, going back to 2017 when PJM filed changes to comply with a FERC Accepts PJM’s FTR Plan, Rejects Rehearing Requests.)

The issue took on greater importance after the 2018 GreenHat Energy credit default, PJM said, calling into question the credit requirements for FTRs and the value of the long-term FTR auction. Subsequent discussions at the ARR/FTR Market Task Force have resulted in movements to alter the auction structure.

As a recommendation contained in the independent consultant report on the GreenHat default released last year, PJM is conducting a “holistic review” of the ARR/FTR products and procedures and is in the process of hiring a consultant to conduct a review. PJM reviewed the final scope for the holistic review to be done by the consultant at the June 26 task force meeting. (See PJM Revises Consultant Scope for ARR/FTR Review.)

“PJM is engaging in this holistic review with an open mind and looks forward to working with Monitoring Analytics and stakeholders on the consultant’s final report,” PJM wrote in its response. “The current structure that is implemented in PJM has been in place for over 20 years. That length of time, in addition to questions raised by stakeholders on the effectiveness of the current structure, necessitates such a review.”

5-Minute Dispatch and Pricing

In May 2019, the Monitor presented a problem statement and issue charge to the Market Implementation Committee addressing transparency and process improvements for real-time energy price formation.

Since then, stakeholders have discussed market rule changes and areas to increase transparency in the governing documents. Several key changes remain under discussion, including: the alignment of energy and reserve prices with the target time of the dispatch instructions; the configuration and periodicity of the dispatch algorithm; the formulation of the real-time dispatch and pricing; and the transparency of the LMP verification process performed by PJM.

Members gave a nearly unanimous endorsement of PJM’s short-term proposal to resolve issues in five-minute dispatch and pricing at the June 3 MIC meeting, while urging the RTO to continue seeking intermediate and long-term solutions. (See PJM 5-Minute Dispatch Proposal Endorsed.)

PJM said changes in the alignment of prices and dispatch instructions and frequency and configuration of the dispatch algorithm are “beneficial” and will increase incentives to follow dispatch. The RTO said it cannot currently support proposed changes to the formulation of the real-time dispatch because no analysis is available determining the benefits, costs or operational impacts related to the proposal.

PJM said it appreciates the Monitor raising issues regarding transparency and process improvements around real-time energy price formation.

“The real-time dispatch and pricing of the PJM system is complex,” it said. “Taking time to identify where those processes may be improved and where more transparency would be beneficial is important to PJM.”

Default Market Seller Offer Cap

Stakeholders discussed changes to the capacity market’s default market seller offer cap (MSOC) at the MIC in 2017 and 2018, advancing a proposal by PJM before it ultimately failed to pass at the October 2018 Members Committee meeting. (See “Market Seller Offer Cap Balancing Ratio,” PJM MRC/MC Briefs: Oct. 25, 2018.)

The default MSOC is defined as the net cost of new entry multiplied by the average balancing ratio for all performance assessment intervals in the prior three years. The proposal would have calculated the balancing ratio used in the default MSOC and nonperformance charge rate formulas by averaging the balancing ratios from the three delivery years that immediately preceded the capacity auction.

Despite lengthy discussions on the issue, consensus was not reached on changes. In February 2019, the Monitor filed a complaint with FERC explaining the problems it believes exist with the current default MSOC (EL19-47). (See Monitor Asks FERC to Cut PJM Capacity Offer Cap.)

The complaint has yet to be resolved at FERC. PJM said it understands the IMM’s justification for the complaint and recognizes that it has resulted in uncertainty in capacity market rules but would have preferred to address the issues outside of FERC rather than waiting for an answer.

UTC Transactions

As a result of changes in market behavior and stakeholder questions on the value of up-to-congestion (UTC) transactions, PJM wrote a paper in 2015 providing background and education on their value and highlighted concerns with their use. Recommendations included altering the biddable locations for UTCs to generation buses as source only, trading hubs, load zones and interfaces and allocating uplift to UTCs consistent with increment offers (INCs) and decrement bids (DECs).

The recommendations were discussed at the Energy Market Uplift Senior Task Force and culminated in two separate FERC filings, the first of which was accepted in February 2018 and decreased the bidding nodes for virtual transactions in PJM. (See FERC OKs Slash in Virtual B idding Nodes for PJM.)

The second filing, which was rejected by FERC in January 2018, proposed to allocate a portion of the uplift in PJM to UTCs as if they were an INC at the injection point and a DEC at the withdrawal point. PJM and stakeholders chose not to propose an alternative in response to FERC’s invitation to do so in its order. (See FERC Queries PJM on Virtual Transaction Rules.)

PJM said it believes inconsistencies in the allocation of uplift costs existing between UTCs and other virtual transactions is “inequitable” and should be addressed. The RTO is currently working with the Monitor on UTC analysis.

Energy Market Power Mitigation

PJM said its energy market power mitigation rules have been the frequent focus of stakeholder discussions and “have presented challenges,” including debate over the fuel-cost policy (FCP) process, the lost opportunity cost calculator and parameter-limited scheduling.

In September 2018, stakeholders approved a problem statement and issue charge focused on enhancing the FCP process and to explore potential alternatives to PJM’s cost-based offer rules. Discussions on the topic are currently taking place within the stakeholder process, as members approved rule changes at the March MC meeting. (See Revised Fuel-cost Policy Approved by PJM MC.)

PJM said it supports working with stakeholders and the Monitor to investigate ways to “simplify and streamline the current rules without weakening them” but wants to consider several different components of energy market power mitigation rules to make sure they work together.

“PJM firmly believes that strong market power mitigation mechanisms are critical to maintain an efficient, competitive market,” the RTO said. “To ensure those rules remain strong and that they all function cohesively, PJM believes that substantive changes to the calculation of cost-based or mitigated offers should not be considered in isolation.”

July 2, 2020

Stakeholders Split on Potential MISO RA Requirements

Stakeholders appear torn over whether MISO should proceed with a potentially controversial effort to develop reliability guidelines that could establish uniform resource adequacy criteria across its footprint, stepping into territory currently reserved for the states.

With its own studies showing an emerging wintertime loss-of-load risk, MISO has recently signaled that it may define its own system reliability criteria, possibly as part of its ongoing resource availability and need project.

“The transition to a different portfolio is happening, and happening quickly, I would say,” Jessica Harrison, MISO director of research and development, said during a virtual stakeholder workshop Tuesday.

MISO RA Requirements — Jessica Harrison, MISO | © *RTO Insider*

Harrison said MISO faces interconnection of a growing number of gigawatts from intermittent resources.

“There’s a lot more management that has to happen throughout the year,” she said. “There are strong indicators of change, and there are strong indicators that we need to do something.”

While MISO has yet to define what would be the objectives and outcomes of such an effort, officials have said load-serving entities need the RTO to provide more direction on reliability in order to make resource investment decisions.

“People are asking us now, ‘I have a billion-dollar investment. It’s a decade-long asset. Will we need this?’” Executive Vice President of Market and Grid Strategy Richard Doying said at MISO’s Board of Directors meeting last month.

“We need MISO to provide forward-looking guidance,” Xcel Energy’s Kari Hassler said. She said the MISO footprint should operate according to a single set of reliability criteria instead of several disjointed sets established by state regulators.

But other stakeholders said such a requirement would tread on states’ jurisdiction over resource adequacy and their prerogative to create their own resource mixes.

Mississippi Public Service Commission consultant Bill Booth said Mississippi is only looking to MISO to provide annual local clearing requirements and planning reserve margins, which the state adopts only when it agrees with the RTO’s assessment.

“I don’t think Mississippi is looking to MISO for anything beyond those,” Booth said.

But Gabel Associates’ Travis Stewart said inaction by MISO could result in some states developing insufficient resource mixes and enjoying “free ridership,” where one state relies on ratepayers in other states for resource adequacy.

“This is very much the dynamic in some loads,” he said, adding that if loads decide to go 100% solar, they should include reliability mechanisms.

Stewart said MISO can help by developing market rules that send economic signals that incent jurisdictions to build or retire reliably.

July 2, 2020April 22, 2024

Tri-State, Delta Officially Part Ways

Tri-State Generation and Transmission Association and Delta-Montrose Electric Association (DMEA) officially parted ways Tuesday, wishing each other well after 28 years of partnership.

The two cooperatives in April entered into a membership withdrawal agreement in which DMEA agreed to pay an $88.5 million exit fee in accordance with a July 2019 settlement agreement. (See Tri-State G&T, Delta-Montrose Reach Withdrawal Deal.)

FERC approved the breakup in June (ER20-1541, et al.). The Colorado Public Utilities Commission accepted the settlement agreement last year.

In a joint press release, each of the cooperatives’ CEOs extended best wishes to the other organization and its members. It was a friendly ending to a relationship that had turned acrimonious over the last 15 years. DMEA refused Tri-State’s 2005 request of its members to extend their contract from 2040 to 2050 to help pay for a coal-fired plant in western Kansas. Tri-State eventually pulled out of the Holcomb project and has begun a shift to renewable power as part of its Responsible Energy Plan. (See Tri-State to Retire 2 Coal Plants, Mine.)

In 2016, DMEA served notice to Tri-State that it planned to leave the partnership, saying it wanted to pursue cheaper renewable power and escape rates that had risen 56% since 2005. Tri-State initially asked for a reported $322 exit fee but settled with DMEA on the final amount.

Wholesale provider Guzman Energy, which has entered into a contract with DMEA, will pay Tri-State $72 million for DMEA’s contract while the co-op will pony up $26 million to Tri-State for transmission assets. DMEA also forfeited another $48 million in patronage capital to depart.

Tri-State and DMEA have also entered into new contracts for the continued operation of transmission and telecommunications systems.

“This separation marks a new chapter for both DMEA and for Tri-State, and as cooperatives, we both know it’s important to look forward for the benefit of our members,” DMEA CEO Jasen Bronec said. “We recognize our ongoing partnership with Tri-State in various areas, such as transmission, and appreciate the importance of our continued cooperation.”

DMEA, a rural distribution cooperative that serves about 28,000 member-owners in western Colorado, is the second member to leave Tri-State in recent years. Kit Carson Electric Cooperative left in 2016, with Guzman paying its $37 million exit fee.

Westminster, Colo.-based Tri-State is a not-for-profit cooperative with 45 members following DMEA’s exit. It has 42 member utility distribution cooperatives and public power districts in four states, with more than a million customers in nearly 200,000 square miles of the West.

Two of Tri-State’s three largest remaining cooperatives, United Power and La Plata Electric Association, are seeking their own early exits through proceedings at the Colorado PUC.

FERC in June set hearing and settlement judge procedures on Tri-State’s proposal for computing member exit fees (ER20-1559). The commission accepted Tri-State’s methodology but said it raises issues of material fact that cannot be resolved based on the existing record and has not been shown to be just and reasonable. (See FERC Sets Tri-State’s Exit-fee Rules for Hearing.)