Page 1152 – RTO Insider

January 19, 2020

PJM MRC/MC Preview: Jan. 23, 2020

Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members committee meetings Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be in Valley Forge, Pa., covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

Consent Agenda (9:10-9:15)

B. Manual 38: Operations Planning — updates from the periodic cover-to-cover review and updated procedures.

1. Modeling Generation Senior Task Force (9:15-9:30)

After deferring on the issue in December, the MRC will consider a rule change that would implement “soak time” modeling of resources. (See “Modeling Generation Senior Task Force Recommendations,” PJM MRC Briefs: Dec. 19, 2019.)

The MRC endorsed recommendations from the task force last month that can be implemented in the near term while PJM focuses on completion of its next generation energy market (nGEM). But stakeholders requested more time to investigate the soak time recommendation after expressing concerns about the time and energy it would require.

Soak time refers to the minimum period a unit must run from the generator breaker closure until it is dispatchable.

The Modeling Generation Senior Task Force (MGSTF), assembled in 2017, developed the solutions to improve resource modeling for “complex resources” in PJM’s market clearing engines, including combined cycle units, coal units with multiple mills and pumped hydro.

2. Primary Frequency Response Task Force Update (9:30-9:40)

The committee will decide whether to keep the Primary Frequency Response Task Force on hiatus through the first half of 2020.

Primary frequency response (PFR) is the ability of generators to automatically change their output in five to 15 seconds when the grid’s frequency strays above or below 60 Hz. As more renewables enter the resource mix and coal plants retire, the grid can become more susceptible to these frequency swings, threatening system reliability.

In October, PJM said 583 units with capacities of 50 MW or greater were evaluated for PFR across 10 events between March and September. The selected events for analysis met one of three qualifications: frequency goes outside the +/- 40-MHz deadband, frequency stays outside the +/- 40-MHz deadband for 60 continuous seconds or minimum/maximum frequency reaches +/- 53 MHz.

No more than 28 units provided PFR during any of the selected events. In some cases, no units responded. PJM said most critical load and black start units evaluated did not provide PFR because many were offline, operating at maximum capacity or had inconclusive results.

The task force would continue to update the Operating Committee on a quarterly basis of PFR results across the RTO.

Members Committee

Consent Agenda (11:05-11:10)

The MC will be asked to endorse:

B. r evisions to the Operating Agreement endorsed by the Financial Risk Mitigation Senior Task Force and MRC to hold five long-term financial transmission rights auctions a year, instead of three, to increase oversight and visibility into portfolio conditions so that more collateral can be collected if necessary. The revisions also would alter the structure of Balancing of Planning Period auctions so that participants can buy and sell in any month of the year, rather than being limited to a specific quarter. (See “FTR Credit Rules Endorsed,” PJM MRC Briefs: Dec. 19, 2019.)

C. r evisions to the OA to implement changes to the competitive transmission proposal fee structure. PJM will charge a $5,000 nonrefundable flat fee to all developers who submit competitive proposals. Itemized study costs will be added as necessary. RTO officials said the current tiered approach doesn’t account for the increased cost of the new comparison framework that involves an independent consultant’s review and legal and financial analyses. (See “Competitive Transmission Proposal Fee,” PJM MRC Briefs: Dec. 19, 2019.)

D. r evisions to the Tariff and OA related to the hourly differentiated ramp rate changes originating from the MGSTF. The changes will increase the number of segments on the energy offer curve (2020); introduce hourly differentiated segmented ramp rates (late 2020) and implement the soak time parameter referenced in MRC item 1 above (2022).

E. r evisions to the Tariff and OA to align them with PJM’s actual implementation of market-based parameter-limited schedules. (See “Parameter-limited Scheduling Fix,” PJM MRC Briefs: Dec. 19, 2019.)

F. r evisions to the OA clarifying the requirements for sharing forecasted unit commitment data to transmission owners for reliability studies, to ensure consistency with NERC standards and PJM manuals.

1. Members Committee Resolution (11:10-11:35)

The MC could approve an advisory against TOs’ proposal for a new Tariff Attachment M creating a new, confidential process for projects to address NERC critical infrastructure protection standard CIP-014.

LS Power drafted the document and presented it at the Dec. 5 MC meeting as tensions over the TO proposal grow increasingly fraught. (See “Critical Infrastructure Resolution,” PJM MRC/MC Briefs: Dec. 5, 2019.)

The company said the attachment conflicts with the OA because it will move forward without any vetting from the MC. At the heart of company’s argument is a belief that incumbent TOs don’t get exclusive rights to handling critical infrastructure on NERC’s CIP-014 list. Because the projects could carry significant regional implications, LS Power believes PJM should plan their mitigation. (See PJM TO Filing Stirs Up Transparency Concerns.)

Incumbent TOs argue that NERC’s confidentiality standards — and their rights under PJM’s Attachment M-4 process — support their intention to file the mitigation plan at FERC without input from other sectors.

PJM maintained its neutrality in the debate and urged all stakeholders agree about mitigating critical assets so they are no longer vulnerable to attack. (See PJM Remains Neutral in CIP-014 Debate.)

January 19, 2020

NYPSC Expands Energy Efficiency, Indexes RECs

By Michael Kuser

The New York Public Service Commission on Thursday performed some heavy regulatory lifting intended to help the state achieve its ambitious clean energy goals, committing an additional $2 billion to energy efficiency and building-electrification programs. It also created an index renewable energy credit that pays for the environmental attributes of a solar or wind farm (18-M-0084, 15-E-0302).

The energy efficiency order “puts us on a path as a state to save at meaningful levels, and saving is the way of going after the resource we don’t use, which is always the best resource,” PSC Chair John B. Rhodes said. “It leans into the [Climate Leadership and Community Protection Act], taking action now at high levels of achievement, at high levels of distributing that achievement equitably.”

Among other targets, the CLCPA (A8429) signed into law last July aims to raise the state’s energy efficiency savings to 185 trillion BTU by 2025 and greenhouse gas emission reductions by 85% by 2050. (See Cuomo Sets New York’s Green Goals for 2020.)

Various state agencies will coordinate the investments to achieve the new energy efficiency and electric heat pump targets for investor-owned utilities, investments estimated at $6.8 billion from now through 2025.

Commissioner Diane Burman stood alone on the five-member commission in voting against the energy efficiency measure. She urged fiscal and fiduciary prudence and recalled that at the PSC’s November 2019 session, she voted against reallocating uncommitted funds to the New York State Energy Research and Development Authority to administer clean energy programs. (See “CES Budget for 2020,” NYPSC OKs Rebuilding Upstate Tx Lines.)

“I have been a consistent ‘no’ when we are looking to repurpose and reallocate uncommitted funds,” Burman said. “It really begs the question to me: Why not reduce those surcharges or at least be more mindful of those programs in total from the beginning?”

A wide coalition of environmental groups endorsed the move, led by the Natural Resources Defense Council.

“Speed is of the essence when it comes to bending the curve on climate pollution,” Samantha Wilt, NRDC senior policy analyst for climate and clean energy, said in a statement. “There is no cheaper or faster way to do that than investing in energy efficiency. This order also has massive job-creating potential and will improve New Yorkers’ homes and businesses, making them more comfortable, healthier and less polluting.”

Enhancing Tier I RECs

In its order modifying Tier 1 renewable procurements, the commission directed NYSERDA to include an additional option for bidders to offer an indexed REC price in future Renewable Energy Standard (RES) solicitations, beginning with this year’s.

The American Wind Energy Association and the Alliance for Clean Energy New York last March filed a petition asserting that an indexed REC — based on a reference market index that will change monthly over the life of a RES contract — would serve as a hedge against market volatility, lower the financing costs for renewable generators, and provide lower costs and less volatile prices for ratepayers.

“Our decision today will benefit renewable energy developers by reducing their risks while also lowering customer costs,” Rhodes said.

The commission noted that adopting an indexed REC structure will require changes to the RES program, including revisions to the methodology for calculation of its annual Tier 1 REC price associated with sales to load-serving entities for both fixed-price and indexed REC payments.

The order directs NYSERDA and Department of Public Service staff to file an implementation plan within 90 days but notes that approval of the plan is not required prior to issuance of an index REC solicitation.

The Advanced Energy Economy (AEE) Institute commented that an indexed REC could cause more volatility in computing the environmental value because the calculation method is tied to the Tier 1 REC price. It suggested that environmental value might vary by zone and that the social cost of carbon could factor into setting the environmental value if the state implements the NYISO carbon pricing proposal.

The commission found “appropriate” AEE’s suggestion to hold a stakeholder process within the Value of Distributed Energy Resources proceeding to consider the issues (17-01277). (See NYPSC Refines Value Stack, Boosts Community DG.)

Burman, again the only commissioner in opposition, said she voted against the measure “because we already have had experience in these solicitations, in 2018 and 2019, that were robust. We got a lot, we were oversubscribed, so I don’t fear that somehow we need to do this to make the developers be a part of the solicitation.

“My biggest fear is, when I look to NYSERDA, I don’t see enough analysis, and I’m persuaded by New York City’s comments that there should be more substantive, quantitative analysis done to ensure that we are carefully evaluating the risk.”

Susanne DesRoches, of the New York City Mayor’s Office of Recovery and Resiliency, argued in an Oct. 2, 2019, filing that it “is essential to ensure that the potential benefits of lower REC prices are substantial enough to mitigate the added risks to customers that result from moving to an indexed pricing procurement mechanism which shifts project risk away from the developer and onto customers.”

“Given that there are nearly half a million low-income families in New York City who are over the state’s target for spending on energy bills today, it is imperative that customers do not become even more energy cost-burdened as a result of a switch in REC procurement methodologies,” DesRoches said.

January 17, 2020

Ransomware Attack Hits New Mexico Commission

By Rich Heidorn Jr.

The New Mexico Public Regulation Commission’s website and electronic filing system have been offline since a ransomware attack last Thursday, and it is likely to be another week before the sites are restored, state officials said.

Officials initially said the Jan. 9 attack originated from a foreign country but later said that had not been confirmed.

The officials said hackers breached a firewall on outdated state servers, giving them access to the PRC’s system. The internet and intranet were taken offline to prevent further damage.

The state Department of Information Technology “was immediately notified of the intrusion by the PRC and immediately began to quarantine it, address it and investigate it, per protocol,” department spokeswoman Renee Narvaiz told ERO Insider on Thursday. “There is not yet any confirmation about the source of the intrusion; it remains under investigation.”

The New Mexico Public Regulation Commission’s website and electronic filing system have been offline since a ransomware attack Jan. 9, and it is likely to be another week before the sites are restored. | *New Mexico Public Regulation Commission*

The department is investigating the incident along with the FBI and security consultant RiskSense.

Because of the loss of electronic filing, the commission is only accepting documents via mail or hand delivery.

RiskSense CEO Srinivas Mukkamala told ERO Insider he could not comment on early reports that the attack originated outside the U.S. But he said it appeared to be an opportunistic attack by hackers who took sought to profit from the PRC’s failure to practice good “cyber hygiene.”

“It’s unpatched systems on your network that would facilitate an attacker to take advantage,” said Mukkamala, whose company published a report analyzing enterprise ransomware and vulnerabilities in September. “I don’t see a political motive here.”

Mukkamala said ransomware attackers are like pickpockets scanning passengers on a subway car for those who are inattentive. “Pay attention to your wallet. If not, somebody is going to pick your wallet off,” he said. “It comes down to two things: Pay attention to the software you’re using to run your organization. Pay attention to the data you’re collecting and storing.”

Mukkamala said it was difficult to predict how soon the PRC’s systems will be returned to service.

“In scenarios like this, it can be today; it can be tomorrow; it could be a week from now. So, we cannot give a definite answer. The reason is we have to look at exposure. While there is one system identified as being infected, we have to look at what else is in the network that [is] susceptible to [a similar attack]. … So, the recovery process has to be looked at as a holistic view.”

Mukkamala told SC Media last month that ransomware “will continue to be the growth driver” in cybercrime because “it’s the shortest distance between investment and revenue for its perpetrators. Unlike identity theft, cryptocurrency theft or bank fraud, ransomware is a fast, cheap and effective method of extracting fees from victims.”

He said the growth rate of new ransomware families fell by half last year. “The reason for this is that the families that did appear were more sophisticated, harder to prevent and contained better distribution mechanisms.”

The New Mexico attorney general’s office has asked the legislature for about $500,000 to create a new cybercrime and counterterrorism unit. Attorney General Hector Balderas said in November that the state’s domestic terrorism and cybercrime laws should be revised to give officials more tools to deal with mass shooters and hackers.

Balderas also said he wants a “special unit” to aid New Mexico’s law enforcement in investigations like this.

January 17, 2020

Rooftop PV’s ‘Hidden Loads’ Challenge Grid Planners

By Holden Mann

Distributed energy resources such as rooftop solar panels and batteries may pose a higher risk for electric grid stability than previously thought, the chief engineer for San Diego Gas & Electric warned this week.

Sharing his observations of the more than 179,000 rooftop solar projects in SDG&E’s service territory, Thomas Bialek told NERC’s System Planning Impacts from Distributed Energy Resources (SPIDER) Working Group that the behavior of residential users of PV systems is often quite different than what system planners expect. The biggest contrast: Rather than satisfying part or all of a customer’s existing demand and taking the corresponding load off the wider grid, the installation of solar panels seems to lead customers to use even more power than they normally would.

“Effectively they say, ‘I’ve put a PV system on my roof, or a battery — I’m now in charge, and I’m going to do whatever it is I want to do,’” Bialek said. “What we’ve seen is that the residential customers with solar have maximum 15-minute demands that are 40% higher than those without solar, and … [67%] of residential solar customers have increased their demand in the second year after solar adoption, by … about 60%.”

The gap between expectation and reality has significant implications, creating what Bialek dubbed “hidden loads” that can’t be accounted for in system planning. Thanks in part to the California state government’s efforts to encourage renewable energy production, rooftop solar panels are now the single largest generating resource in SDG&E’s service territory with more than 1,200 MW of peak capacity.

But because utilities are not allowed to monitor the power generated by customers’ DERs, they are unable to use the systems’ capabilities to the extent they would like. For an operator like SDG&E, this means it cannot tune the output of DERs as effectively as it would like; more seriously, it can’t predict how users will behave in the event of widespread service disruptions or account for the possibility of large amounts of distributed generation going offline simultaneously.

Potential Cyber Threats

This scenario is particularly concerning in light of growing efforts by overseas hackers to target U.S. utilities. (See Report: Oil, Gas Hackers Expanding to Grid.) More than 58% of rooftop solar installations in SDG&E’s territory are provided by just two vendors, which poses a significant risk because hackers can often use the same attack vector against multiple types of systems from a single manufacturer.

“We bring that up because this is all behind-the-meter installations. We have our cybersecurity and our firewalls over our interfaces … but we don’t do that for any of the rooftop PV installations that are now using home Wi-Fi,” Bialek said. “To the extent that anyone can get to those particular systems, in our case you’d now be putting out about 600 MW AC [that are] potentially under the control of some bad cyber actor.”

Even without external disruptions, the electronic control systems of DERs can create unexpected issues for both users and utilities because of the complex interactions between software, hardware and the underlying physics of the energy resources themselves. Systems produced by the same manufacturer and even in the same production run can approach the same goal in widely different ways.

Despite these issues, Bialek stressed that the decentralized generation and storage capabilities of DERs can bring significant benefits to the larger grid. However, utilities must remain conservative in their expectations while the regulatory and security environment catches up. “Contrary to what all the DER providers will tell you, not everywhere is an opportune time for a DER to provide a service,” he said.

January 17, 2020

California PUC Devoting $1.2B to Self-generation

By Hudson Sangree

The California Public Utilities Commission on Thursday approved $830 million in incentives for self-generation with the goal of benefiting disadvantaged customers who live in fire-prone areas and have been subject to public safety power shutoffs (PSPS) by utilities trying to avoid starting wildfires.

When added to unspent funds from prior years, that brings the total for the CPUC’s Self-Generation Incentive Program (SGIP) to $1.2 billion.

“Broadly, it shifts the focus of SGIP towards promoting resiliency,” Commissioner Clifford Rechtschaffen said at the commission’s Thursday meeting.

Ninety percent of the new funding will be available to utility customers in communities impacted by wildfires and the threat of wildfires, Rechtschaffen said. It “substantially expands the universe of customers” eligible for incentives to those whose electricity has been shut off at least twice in fire-prevention blackouts, he said.

The unanimous decision orders the state’s largest investor-owned utilities — Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric — to collect a total of $166 million from ratepayers annually during each of the next five years. The changes were authorized by last year’s Senate Bill 700.

The largest category of potential beneficiaries fall under the category of “equity resilience,” Rechtschaffen said.

The efforts could provide full funding for home electricity storage systems for ratepayers in high fire-risk areas, such as the Sierra Nevada foothills and the state’s coastal ranges. Of particular concern, the commission said, are customers who are economically disadvantaged but need constant electricity to run medical devices.

About $400 million of the funds will be available to nonresidential customers in disadvantaged communities that provide critical services such as police and fire. Large-scale storage and renewable generation projects can qualify.

The utilities’ PSPS, allowed under state law and CPUC regulations, have caused tremendous controversy in California since last fall, when PG&E instituted widespread blackouts to prevent the outbreak of wildfires during dry, windy conditions.

PG&E said the shutoffs worked, though it’s trying to narrow the scope of the events going forward. The utility is in bankruptcy following two years of massive wildfires that killed nearly 100 people and destroyed at least 22,000 structures, according to the California Department of Forestry and Fire Protection.

Customers and lawmakers, however, were outraged by the size of the blackouts, which left roughly 2.4 million customers in the dark last October. (See California Officials Hammer PG&E over Power Shutoffs.) PG&E was widely accused of being ill prepared for the shutoffs, especially after the utility’s websites crashed and the state had to step in to help on an emergency basis.

“Although the utilities are ultimately responsible for managing their electric systems, the CPUC cannot and should not stop demanding better ways to reduce the scope and impacts of power shutoffs without compromising public safety,” commission President Marybel Batjer told lawmakers in November. “This cannot and should not be repeated.”

January 17, 2020

Texas PUC Approves EPE’s $4.3B Sale

J.P. Morgan’s proposed $4.3 billion purchase of El Paso Electric cleared a major regulatory hurdle Thursday when the Texas Public Utility Commission approved a modified stipulated settlement (49849).

Commission staff suggested a revision to the order to ensure that no more than two disinterested directors — those board members without direct or indirect financial interest in the transaction — will have their terms expire in the same year as part of the PUC’s ring-fencing measures.

Staff were to file the final order within the next few days.

“Congratulations,” PUC Chair DeAnn Walker told the parties after the commission’s approval.

El Paso Electric — IIF’s Lino Mendiola (left) agrees with Texas PUC Director of Customer Protection Stephen Journeay’s proposed language on disinterested directors.

J.P. Morgan’s Infrastructure Investments Fund (IIF), Sun Jupiter Holdings and EPE reached an agreement in December with PUC staff, the Office of Public Utility Counsel, the city of El Paso, and various consumer and labor groups. (See Parties to EPE Acquisition Reach Settlement Agreement.)

The Rate 41 Group, a coalition of school districts and other public entities, withdrew an earlier motion for continuance on Jan. 3 and indicated it wouldn’t oppose the settlement.

The transaction must still be approved by FERC, the Nuclear Regulatory Commission and the New Mexico Public Regulation Commission, which held a hearing Thursday on a settlement agreement between IIF, EPE and eight intervenors.

PRC Hearing Examiner Carolyn Glick will finalize her recommendations and forward them to the full commission for its final ruling, spokesman Deswood Tome said. “The hearing examiner did not specify a time of when her recommendation will be concluded,” Tome said.

The PRC’s website has been offline since a Jan. 9 ransomware attack. (See Ransomware Attack Hits New Mexico Commission.)

— Tom Kleckner

January 17, 2020

MWEX Study Could Elicit New Tx Planning for MISO

By Amanda Durish Cook

CARMEL, Ind. — MISO’s special analysis into the Minnesota-Wisconsin export interface constraint could inspire similar studies to solve non-thermal operating limits in other parts of its system.

“We are expecting several non-thermal constraints in the future, including voltage issues [and] stability issues that will limit the delivery of energy from high renewable energy penetration to load centers,” MISO Resource Interconnection Planning Manager Neil Shah told stakeholders at the Planning Advisory Committee’s Wednesday meeting.

The constraint, known as MWEX, is the subject of a special study this year as part of the 2020 MISO Transmission Expansion Plan (MTEP 20), dubbed the North Region Economic Transfer Study. (See “MTEP 20 Gains Unique Study,” MTEP 19 Advances to MISO Board Committee.)

MISO said the study will evaluate non-thermal constraints between high renewable areas in the northwestern portion of its footprint and load centers. The RTO said it’s especially expecting “bottlenecks” in its North Region, which already contains high wind penetration.

MISO MWEX study — Neil Shah, MISO | © *RTO Insider*

Shah said the RTO will project the area’s transmission needs 15 years into the future. The study may identify transmission solutions that would be subject to further studies.

He said MWEX has a “long history” in MISO.

“It’s not only being monitored in real time but in other planning studies,” Shah said. “It appears very often in interconnection [studies], especially in MISO North and West.”

Some stakeholders have expressed doubt that an actual project to assist the area will materialize, pointing out that MWEX’s transfer limits are hard-coded as constraints in MISO economic planning models.

Entergy’s Yarrow Etheredge said transmission owners support the study because typical economic studies don’t consider non-thermal operational limits.

Shah said the study would serve as an introduction to MISO evaluating the impact of expected non-thermal system operation limits in other areas of the grid.

“How do we go from informational [study] to project approval?” Clean Grid Alliance’s Natalie McIntire asked, with others echoing the question.

“We’re going to keep our options and use this information in any planning studies open next year or later this year,” Shah said of study results, adding that they may also “feed into” MTEP 21 efforts.

MISO plans to reveal a final study scope by the Feb. 12 PAC meeting. It expects to wrap up the study and announce potential recommendations in September.

January 17, 2020April 14, 2025

NYISO Stakeholders OK Moving IESO Proxy Bus

By Rich Heidorn Jr.

NYISO stakeholders Wednesday approved moving the proxy bus for pricing transactions with Ontario’s Independent Electric System Operator (IESO) from the Bruce station to the Beck station to reflect power-flow changes resulting from the implementation of the Ontario-Michigan phase-angle regulators.

The proxy bus, intended to represent a typical bus in an adjacent control area, is where locational-based marginal prices are calculated.

NYISO Operations Analysis and Services Supervisor Tolu Dina told the Business Issues Committee that the implementation of the Ontario-Michigan PARs in July 2012 has resulted in 85 to 95% of IESO-NY interchange being delivered directly to New York rather than looping counterclockwise around Lake Erie as before the PARs.

Dina said the power flow of four free flow ties — the 345-kV Beck-Niagara (PA301) and Beck-Niagara (PA302), and the 230-kV Beck-Niagara (PA27) and Beck-Packard (BP76) — is affected by the external proxy bus location.

The current market model using the Bruce proxy assumes only 73% of the flow over the IESO-NY interface. The new model using the Beck bus will increase the model’s assumption to about 87% of the total.

Making the change is contingent on the replacement of NYISO’s energy management system (EMS) and business management system (BMS). The ISO is targeting April for updating its model to reflect the switch from Bruce to Beck.

As a transition, the spring 2020 transmission congestion contract (TCC) auction — expected to begin Feb. 7 and end April 9 — will only allow bids at the IESO bus for the six-month auction. No bids will be permitted at the bus for the one- and two-year rounds.

The BIC approved the change with no opposition.

2021-2025 ICAP Demand Curve Reset

The BIC also approved NYISO’s proposed Tariff change to modify how it calculates gross cost of new entry (CONE) escalation factor as part of the annual updates of the installed capacity demand curves.

The gross CONE escalation factor includes four components: changes in construction material costs, turbine generator costs, labor costs and general costs of goods and services.

The proposal would switch from the current methodology, which measures changes on a year-to-year basis, to one that measures changes over the term of each reset period using the first year as a baseline.

It is intended to address the New York Transmission Owners’ concerns that the current year-to-year determination could be misleading if past index values that are subsequently reutilized are updated by an index publisher or if the relative change in the cost components change at materially different rates over time, the ISO said.

If approved by the Management Committee on Jan. 22 and the Board of Directors in February, the changes will be filed with FERC in February or March.

January 15, 2020

FEMA Wants $4 Billion from PG&E in Bankruptcy

By Hudson Sangree

The Federal Emergency Management Agency’s claims that Pacific Gas and Electric owes it more than $3.9 billion have thrown the utility’s Chapter 11 case into disarray, just as it seemed on a steadier course toward conclusion.

FEMA is seeking reimbursement for its expenses following disastrous wildfires ignited by PG&E equipment, including the Camp Fire, which killed 86 people and leveled the town of Paradise in November 2018.

Wildfire victims and their lawyers are worried the money could come out of a $13.5 billion trust that PG&E agreed to fund with cash and stock for those who suffered from the fires. FEMA’s statements this week that it could seek reimbursement directly from some victims added to the outrage.

“FEMA is taxpayer funded, as you know, and it is very unfair for them to get any of our settlement, period!” Camp Fire victim Brenda Wright wrote to U.S. Bankruptcy Court Judge Dennis Montali, who is overseeing the Chapter 11 case. “Please take this into consideration as you proceed. FEMA doesn’t deserve any of this money. Please man up and do the right thing for us.”

Lawyers for fire victims argued in court papers that the agency wasn’t entitled to share in the settlement funds or to recover from PG&E.

FEMA PG&E bankruptcy — Aftermath of Camp Fire in Butte County, Calif. | *California Governor’s Office of Emergency Services*

More than 72,000 proofs of claim have been filed by residents and businesses harmed by the Butte Fire of September 2015, the 22 Northern California wine country fires of October 2017 and the Camp Fire. PG&E is liable for the victims’ damages because the utility’s faulty electric lines and equipment ignited the fires, “but it does not follow from this that the debtors are also liable to FEMA,” the attorneys wrote.

On Monday, FEMA Regional Administrator Robert Fenton held a conference call with reporters in which he said the agency could try to recover approximately $200 million from fire victims who received funds from FEMA and other sources for the same losses, according to the Associated P ress. But that wasn’t the agency’s preferred course, he said.

“We want to help people after a disaster,” the AP reported Fenton saying. “The last thing we want to do is to hurt them.”

FEMA said it was excluded from confidential settlement talks that resulted in the $13.5 billion settlement agreement, leaving it in its current position. It said in a statement that it is legally required to try to recover public funds from those that cause disasters.

“Responsible third parties should not be unjustly enriched at the taxpayer’s expense,” the agency said.

Montali approved PG&E’s settlement with victims represented by the official tort claimants committee [TCC] Dec. 17, moving PG&E closer to having its reorganization plan confirmed by the court. (See Judge OKs PG&E Deals wi t h Fire Victims, Insurers.)

PG&E is trying to exit bankruptcy by June 30 to participate in an $21 billion state wildfire recovery fund. It doesn’t want the FEMA controversy to derail those plans.

“PG&E agrees with the tort claimants committee that FEMA does not have a valid legal claim against the company,” the utility said in a statement. “The bankruptcy court has approved our settlement agreements resolving all major wildfire claims. This brings us one significant step closer to getting victims paid so they can rebuild their lives.”

“As for our overall plan of reorganization, we remain engaged in active and constructive dialogue with stakeholders,” the utility said. “We are committed to a safe and financially stable PG&E going forward.”

PG&E and FEMA have not responded in court filings to the TCC’s objections. The matter originally was scheduled to be heard in Montali’s San Francisco courtroom Tuesday, but the hearing was postponed to Feb. 11.

January 15, 2020

NYISO Prepares Hybrid Storage Market Participation

By Michael Kuser

RENSSELAER, N.Y. — NYISO kicked off an effort Monday to develop a model for allowing large front-of-the-meter energy storage resources paired with generation to participate in its markets.

The Hybrid Storage Model project will evaluate the possibility of enabling co-located storage resources to receive a single dispatch schedule, Amanda Myott, NYISO capacity market design specialist, t o ld the Installed Capacity/Market Issues Working Group (ICAP-MIWG).

NYISO sees developers increasingly coupling generation resources with storage resources, but its market rules do not include a participation model for such resources. Co-located resources are currently required to be separately metered and have their own point identifier, Myott said.

The ISO has filed related market rules for co-located distributed energy resources and energy storage resources (ESRs) with FERC (ER19-2276).

FERC in December partially accepted the ISO’s plan to comply with a mandate to develop rules to provide energy ESRs full access to their wholesale markets. (See FERC Partially Accepts NYISO Storage Com p liance.)

However, the commission also required NYISO to alter its Tariff to provide more details on its “metering methodology and accounting practices for [ESRs] located behind a customer meter.”

Project Details

Asked where the hybrid model would fit in the ISO’s market structure, Myott said, “We imagine where DER caps at 20 MW, hybrid storage could fit in above that.”

Zachary Smith, the ISO’s manager for capacity market design, stepped in to answer whether hybrid storage would be eligible to withdraw electricity from the grid to alleviate excess supply.

“We would consider a hybrid storage resource to be similar to a DER aggregation, and any DER aggregation that contains storage is eligible to bid withdrawal,” Smith said.

Mark Younger, of Hudson Energy Economics, wanted the ISO to clarify what it meant by co-located: “Two resources connecting into the same interconnection node, whether 345 kV or 115 kV — is that what same location means at its most basic?”

“Yes, that was our initial thinking for resources at the same physical location,” said Mike DeSocio, the ISO’s director of market design.

Myott said the market design could be multifaceted, with some elements of the design being advanced faster than others. The elements include participation in NYISO’s energy, ancillary services and installed capacity markets; a settlement process; modeling for interconnection, planning and operations; and metering requirements.

Hybrid Resources as Power Plants

Explosive growth in solar plus storage projects — both co-located and full hybrid designs — is driving the market, sa i d Mark Ahlstrom, vice president of renewable energy policy at NextEra Energy Resources and president of non-profit Energy Systems Integration Group, who presented on hybrid resources being offered into the market as conventional generators.

NYISO Hybrid Storage — PV inverters harvest DC input when the array or string voltage is above a certain threshold. This impacts generation at beginning of day, end of day and in heavy cloud cover. | *DynaPower*

“A hybrid is a completely different beast, it’s no longer just a PV plant,” Ahlstrom said.

“All that I’m showing you has been shared industry-wide at [the Energy Systems Integration Group], NERC and other meetings, because we all know we have to work it out together,” Ahlstrom said. “And all this is fresh, from the last 12 months. California is perhaps the furthest along, now taking comments on their second straw proposal for hybrid resources, such as solar PV plus lithium-ion storage.”

“AC coupling of PV and storage as the same point of interconnection is what you think of first, and that can work. But DC-coupled designs have a number of attractive features that can increase efficiency and make them more cost effective. For example, AC inverters have to get up to a minimum DC voltage level before they can convert the DC power from the PV panels to AC power, but a DC-to-DC converter can work at lower voltage levels to move energy into the batteries, say, when the sun is just coming up,” he said.

Oversizing the PV panels on the DC side allows access to “a lot of capability sitting there … energy that would otherwise be thrown away, unable to be put on the grid, but can now be used to charge the batteries and later provide many services to the grid,” Ahlstrom said. “And it doesn’t have to be renewables; it could be gas plus storage.”

He advocated an “intelligent agent” approach based on analytics whereby the hybrid operator internalizes the characteristics of the components of the hybrid resource behind the point of interconnection (POI) and offers energy or ancillary services at the POI in the same way as a conventional resource, but with more flexibility and fewer constraints.

“We expect it to be treated like a conventional resource, not like a renewable resource,” Ahlstrom said. “You manage the state of charge through your offers.”

In describing the benefits to system or market operators, Ahlstrom said the “big breakthrough for me about a year ago” was when he saw how hybrid resources do not need to curtail renewable output for the headroom required to provide other need services (such as frequency response), which is instead a function of the battery’s state of charge. “Battery flexibility is what drives all of this,” he said.

Ahlstrom asserted that operated as a single resource, hybrid resources will eventually change market products, market design and market participation.

With no advance commitment, startup costs, minimum generation levels or other constraints, Ahlstrom asked, “will we build standalone storage, or mostly just hybrid resources?”

He closed by posing more questions: “Which is better, a highly flexible generator or a battery storage resource? What, exactly, is the difference? How does it affect planning, markets and operations?”

NYISO plans to complete the Hybrid Storage Model proposal this fall.