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November 19, 2024

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PJM MRC/MC Preview: Feb. 24, 2022

Below is a summary of the consent agendas scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings Thursday. Besides the consent agendas, the committees will not vote on any items at the meetings. The MRC will, however, hear first readings of seven different proposals, potentially teeing up as many votes at next month’s meeting.

Markets and Reliability Committee

Consent Agenda (9:15-9:20)

B. Stakeholders will be asked to endorse proposed conforming revisions to Manual 27: Open Access Transmission Tariff Accounting as a result of PJM’s recent formula rate filing with FERC (ER22-26). (See FERC Sets Hearing on Industrials’ Challenge to PJM Administrative Rates.)

C. Members will be asked to endorse proposed revisions to Manual 40: Training and Certification Requirements resulting from its periodic review. The changes were endorsed by the Operating Committee on Feb. 10. (See “Manual 40 Endorsed,” PJM Operating Committee Briefs: Feb. 10, 2022.)

Members Committee

Consent Agenda (11:25-11:30)

C. The committee will be asked to endorse proposed revisions to the Operating Agreement and Manual 15: Cost Development Guidelines addressing clarifications to fuel-cost policy standards and Schedule 2 penalty revisions. Members unanimously endorsed the joint PJM/Independent Market Monitor proposal at the Jan. 26 MRC meeting. (See “Fuel-cost Policy Standard Clarifications Endorsed,” PJM MRC/MC Briefs: Jan. 26, 2022.)

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Builders Oppose Labor Provision in Washington Solar Canopy Bill

The labor practices component of a Washington solar power bill has drawn opposition from construction interests in the state.

On Thursday, the Washington Senate’s Ways and Means committee heard testimony on a bill to grant tax breaks to solar canopies built over large parking lots in urban areas. Senate Bill 5714 was introduced by Sen. Reuven Carlyle, (D), chairman of the Environment, Energy and Technology Committee, who got the idea for the legislation from the global climate summit held in Glasgow, Scotland last fall.

Carlyle described a scenario in which a typical Walmart parking lot covers five acres and a canopy of solar panels could be built over one acre of it, locating solar farms within towns and cities.

His bill would provide tax breaks to those efforts if the builder approaches the Washington Department of Revenue in advance and meets certain criteria. The breaks would consist of repayments of sales and use taxes accumulated during construction.  Construction would have to be completed in two years to receive all requested tax breaks.

Under the bill, a qualifying project must be at least 50,000 square feet and have a nameplate capacity of 1 MW. The solar canopy installer would receive a 50% refund or deferral of its taxes if it is an organization owned by women, minorities, or veterans, or an entity with a history of complying with federal and state wage and hour laws, apprenticeship utilization and using preferred entry workers living in the project construction area.

Refunds or deferrals of 75% would go to one of those organizations if workers on a project were compensated at prevailing wages determined by collective bargaining agreements.

A 100% refund would go to a contractor operating under a community workforce agreement or a project labor agreement (PLA), which is a special collective bargaining agreement tailored to a specific project that supersedes existing bargaining agreements.  A typical PLA requires that workers are hired through union halls, and that nonunion workers are paid union wages for the length of the project. Also, the contractor must follow union rules on work conditions, pensions and disputes.

The PLA requirement for a 100% tax exemption prompted opposition from two contractor organizations — Associated Builders and Contractors of Washington and Associated General Contractors of Washington, who asked that the provision be removed from the legislation.

“The PLA language is totally unnecessary,” said Jerry VanderWood, chief lobbyist for the Associated General Contractors.

The two contractor associations were the only ones that testified about the bill Thursday.

At a Jan. 13 hearing before the Senate energy committee, several groups supported the use of parking lots as solar canopy sites at locations in or next to cities, saying the structures would help protect habitat and green spaces that would normally host solar farms. The canopies would also prove shade in the summer and shelter in the winter, according to testimony.

At the same hearing, Todd Myers, director of the conservative Washington Policy Center, testified that solar power is not cost-efficient, and that rainy and heavily urban Western Washington would be a poor location for solar resources.

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FERC Opens Inquiry on Dynamic Line Ratings

FERC opened a Notice of Inquiry Thursday to build an evidentiary record on the use of dynamic line ratings (DLRs), an initiative it signaled in its Dec. 16 order calling for the end of static transmission line ratings.

The December order required transmission providers to employ ambient-adjusted ratings (AARs) for short-term transmission requests for all lines that are impacted by air temperature (RM20-16, Order 881). But the commission did not mandate the use of DLRs, saying more evidence was needed concerning DLRs’ costs and benefits. (See FERC Orders End to Static Tx Line Ratings.)

Thursday’s NOI solicits comments on potential criteria for DLR requirements, the benefits, costs and challenges of implementing DLRs, and timeframes for implementation. It also asks whether the lack of DLR requirements makes wholesale rates unjust and unreasonable (AD22-5). In the December order, the commission said the use of only seasonal and static ratings was unjust and unreasonable because it resulted in the underutilization of available transmission capacity.

Initial comments are due 60 days after publication in the Federal Register, with replies due 30 days later.

AARs vs. DLRs

While AARs are based on forecasted ambient air temperatures and the presence or absence of solar heating, DLRs also consider wind, cloud cover, solar heating intensity, precipitation and line conditions such as tension or sag.

The December order required transmission providers to use AARs as the basis for evaluating transmission service requests ending within 10 days. It also required providers to electronically update transmission line ratings at least hourly to allow for use of DLRs by transmission owners that voluntarily adopt them.

The order acknowledged that DLRs can benefit customers when the limiting element of a congested transmission facility is the conductor and conditions besides ambient air temperature impact the line’s capacity. It also noted that in addition to often allowing greater power flows, DLRs can also detect situations where power flows should be reduced to maintain safety and reliability.

Costs

But the commission said it could not consider mandating DLRs without more information on their costs and challenges, such as the costs of sensors and cybersecurity.

In the Order 881 proceeding, some, including SPP’s Market Monitoring Unit and industrial customers, endorsed DLRs. But, FERC noted, “many commenters, including nearly all transmission owners that filed comments about DLRs, either opposed a requirement to implement DLRs on all transmission lines or opposed a DLR requirement in any form.”

FERC cited Bonneville Power Administration’s estimate that DLR implementation would cost more than $1 million per transmission line in monitoring equipment, software and hardware, and MISO Transmission Owners’ estimate of $100,000 to $200,000 per transmission line, or $1.5 billion for the entire RTO. SPP said DLR could require an energy management system (EMS) upgrade at a cost of up to $1 million.

Among the NOI’s 29 questions were queries on:

  • whether FERC should require DLR implementation on all or only certain transmission lines, and what criteria (e.g., congestion, curtailment levels, voltage levels, infrastructure, and/or geography/terrain) it should use to decide;
  • whether FERC should regularly reevaluate lines to ensure its criteria still apply;
  • whether there are differences between RTOs/ISOs and non-RTO/ISO transmission providers that the commission should consider;
  • how DLR requirements should be considered in regional transmission planning and interconnection processes;
  • what transparency measures the commission should require (e.g., informational reports that show which transmission lines meet criteria for DLR implementation);
  • the potential impacts to reliability if the digital devices that monitor or communicate line conditions are hacked in a cyber event;
  • whether FERC should order NERC to evaluate how a DLR requirement could introduce risks to the operation of the bulk electric system and whether any standards require modification to address risks;
  • whether FERC should require the use of sensors or just more up-to-date weather forecasts than required in Order 881;
  • how often transmission providers should be required to calculate transmission line ratings and for what services (e.g., hourly point-to-point; daily point-to-point; weekly point-to-point, etc.);
  • whether the commission should limit the number or proportion of transmission elements on which a transmission provider must implement DLRs at any one time; and
  • the appropriate time frame for identifying which lines are subject to DLRs, designing a DLR system, and integration and testing of the system.
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NERC: Grid Transformation Continues to Accelerate

The ERO Enterprise recommitted itself to adapting to meet its growing challenges in 2021, including the ongoing COVID-19 pandemic, climate change and cybersecurity, NERC said in its annual report released Wednesday.

NERC CEO Jim Robb wrote in the report that the previous two years have “brought significant clarity” to the cyber and climate risks, with both vividly on display in 2021. The year was bookended by the discovery of major electronic supply chain security breaches, with the SolarWinds Orion compromise coming to light in December 2020 and the Apache Log4j vulnerability identified a year later; meanwhile, the massive outages in Texas caused by February’s severe winter storms illustrated the danger facing the current electric grid under rapidly shifting climate patterns.

“We are at a historic moment,” Robb said. “Our model was developed during a time when risks were well known and the grid was evolving at a measured pace. We are now in a time where significant risks are emerging; they are new and unfamiliar; and the grid is transforming at a significant pace.”

Transformation was a major theme of the report, both as it relates to the grid’s transition to new energy sources and digital control, and concerning the organization of the ERO Enterprise itself. For the latter NERC noted the launch of its “NERC 2.0 – Invented Future” initiative in 2021, the name of which “recognizes that … NERC employees have the opportunity to innovate and create the future they want to have for themselves every day.”

The initiative comprises a new flexible work model that gives employees more freedom to work remotely — inspired in part by the experience of the COVID-19 pandemic — as well as new training that encourages employees to take on leadership roles. NERC also created the post of vice president of people and culture to oversee the initiative; the first and current holder of the role is Bryan Preston, who joined the organization in September. (See “Trustees Re-elected; Leadership Shuffle at MRC, Board Committees,” NERC Board of Trustees/MRC Briefs: Feb. 10, 2022.)

For the grid transformation, the report observed that “the past year has seen the manifestation” of multiple risks relating to “the transition to a cleaner energy future,” meaning the replacement of conventional generation resources with renewables like wind and solar, along with the growth of distributed energy resources.

First is extreme weather: Much of the report is dedicated to NERC’s actions over the past year to prevent another near-breakdown of the grid like what nearly happened in Texas. (See ERCOT: Grid was ‘Seconds and Minutes’ from Total Collapse.) Those efforts include accelerating approval of the cold weather standard that was under development before the storm; initiating work on a new standard inspired by the recommendations from FERC and NERC’s joint inquiry on the storm; and NERC’s outreach to industry to encourage preparedness ahead of the current winter season.

The other major risk that the report points out is cybersecurity, particularly the supply chain risks highlighted by the SolarWinds and Log4j compromises, but also the potential weaknesses in the nation’s pipeline infrastructure exposed by the Colonial Pipeline ransomware attack in May. (See Colonial CEO Welcomes Federal Cyber Assistance.)

NERC observed that the industry has grown more reliant on remote work because of the pandemic, creating “an increased remote cybersecurity attack surface” that, coupled with known weaknesses in widely used software, gives potential attackers myriad opportunities to infiltrate critical systems. The organization called for itself and the industry to “maintain a continued focus on improving defenses by increased sharing with” the Electricity Information Sharing and Analysis Center.

NERC Board of Trustees Chair Ken DeFontes warned that “significant policy and technical forces” are driving change in the grid, and that “these changes are occurring at a rapid pace.” He said that the board’s three top priorities for 2021 — weatherization, energy reliability assurance and cybersecurity — will likely remain at the top of the organization’s mind “for some time.”

“The more complex the system becomes, the greater the risk to reliability, resilience and security. At the same time, the future offers exciting new opportunities and transitions for an industry that is amazingly adaptive to change,” DeFontes said. “I look forward to working with all of our stakeholders and policymakers as we rededicate and reorient ourselves to meeting these challenges.”

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Advocates Seek Pathway for Biofuels in New Connecticut Energy Strategy

Representatives of the biofuels industry asked Connecticut regulators Thursday to acknowledge liquid fuels in the state’s 2022 energy plan as a near-term option for reducing greenhouse gas emissions.

“Bioheat should be an established carbon-reducing pathway in the Comprehensive Energy Strategy (CES),” said Stephen Dodge, director of state regulatory affairs for Clean Fuels Alliance America (CFAA).

Electrification cannot “realistically” be the only path to emission reductions, when heating fuel blended with biodiesel can reduce GHGs “immediately,” he said during a Connecticut Department of Energy and Environmental Protection (DEEP) CES scoping meeting.

In its 2018 energy strategy update, DEEP credited biodiesel with improving air quality and reducing GHG emissions and called for further assessment of biodiesel market maturity. Displacing fossil fuels with biodiesel, the CES said, would require tracking feedstock sources, manufacturing, and amount sold and consumed.

DEEP accepted public comments at the scoping meeting as part of its proceeding to update the CES.

Dodge pointed to New York, Rhode Island and Massachusetts as examples of states with an established biodiesel pathway for reducing emissions. Massachusetts regulators recently ruled that electric ratepayer-funded subsidies for liquid fuel-fired home heating should remain in place, he said, after the alliance “successfully argued that bioheat fuel is a legitimate pathway to immediately begin reducing CO2 emissions.”

A study by Trinity Consultants, commissioned by CFAA, found that using 100% biodiesel as a heating oil replacement can reduce carcinogenic diesel particulate matter emissions by 86%.

At a 50% blend, biodiesel would have lower CO2 emissions than power coming from the transmission grid, said Chris Herb, president of the Connecticut Energy Marketers Association.

“Conversions to cold climate heat pumps … will only increase CO2 emissions” compared to biodiesel used for heating, he said.

Herb called for the 2022 CES update to “leverage” a law enacted last year that requires the blending of advanced biofuel with fuel oil starting at 5% in July and increasing to 50% by 2035. That law requires DEEP to consider in the CES how biofuel blends may contribute on a lifecycle basis to meeting the state’s GHG emission reduction targets and how a thermal portfolio standard could contribute to further reductions.

“Hundreds of thousands of homes in our state need little to no modifications … to start using a fuel that is cleaner and has the ability to displace fossil fuels today,” he said.

Advancing bioheat through the CES, he said, would relieve the current pressure to bring enough clean energy onto the electric system to accommodate the state’s efforts toward heat pump and electric vehicle adoption.

The Acadia Center, however, cautioned regulators against using alternative fuels in buildings.

“Numerous studies … have determined that there’s no cost-effective role for alternative fuels, such as renewable natural gas, biodiesel and green hydrogen, in buildings,” said Ben Butterworth, Acadia’s senior manager of climate and energy analysis.

Alternative fuels, he said, are “limited” and “expensive” and should be reserved for decarbonizing hard to electrify sectors, such as heavy industry, shipping and aviation.

Heather Deese, director of policy and regulatory affairs for Dandelion Energy, made the case for geothermal heat pumps, calling them a low-cost option for heating and cooling that significantly reduces GHG emissions.

“In order to provide for an equitable transition of the building stock, the CES should leverage the low ongoing operating costs of geothermal heat pumps,” Deese said, adding that the technology reduces household emissions by up to 80%.

Deese said the CES should set “ambitious” goals for transitioning to a clean energy economy and articulate “specific goals” for building electrification.

DEEP is accepting comments on the scope of the CES through March 3 and expects to publish the final strategy scope by April. The agency will offer additional stakeholder engagement opportunities throughout this year, and it anticipates publishing the final CES by the start of the 2023 legislative session, said Vicki Hackett, DEEP’s deputy commissioner for energy.

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NYPSC Applauds Central Hudson Storm Response

The New York Public Service Commission on Thursday lauded Central Hudson Gas and Electric and assisting utilities for their quick response to the early February blizzard that swept through its service area and cut power to more than 65,000 customers.

The Feb. 3-5 storm dumped up to 18 inches of snow across parts of the state, while freezing rain and cold temperatures lingered mainly in Ulster Duchess and Columbia counties in the mid-Hudson region, with reports of localized icing of one-half to three-quarters of an inch.

“This was the largest workforce Central Hudson has ever assembled in the over 100-year history of their company,” said Kevin Wisely, director of the state’s Office of Resilience and Emergency Preparedness. “The large contingent of workers moving into a concentrated area such as this does pose logistical and significant coordination challenges, particularly with housing and feeding the crews.”

Central Hudson was able to house the emergency crews and has contingency plans in place, if a future need arises, to house additional workers at local universities and colleges, as well as the ability to set up large-scale tented housing units to support an incoming workforce, Wisely said.

National Grid, New York State Electric and Gas, and the Orange and Rockland utilities all provided mutual assistance to Central Hudson.

“Kudos to the utilities for working so well together, but also frankly it was really nice to see that we didn’t have the administration calling for an investigation while the storm was still happening,” Commissioner Diane X. Burman said.

The winter storm once again highlighted the need for utilities to continually reassess infrastructure vulnerabilities across their service territories to determine appropriate storm-hardening and resiliency projects to mitigate potential weather risks and adapt infrastructure to weather extremes, Wisely said.

OKs Enviro Certificate for Tx Line to NYC

The commission on its consent agenda approved a certificate of environmental compatibility and public need for the 1,250-MW Champlain Hudson Power Express (CHPE) developed by Transmission Developers Inc. and Hydro-Québec, as well as a petition for flexible financing practices (10-T-0139 and 20-E-0598).

The PSC will soon rule on a state petition to buy power from two new transmission lines being built to bring more than 2.5 GW of renewable energy into New York City, including the CHPE and the entirely in-state Clean Path NY project (15-E-0302).

Burman cast the lone “no” votes on both measures, saying that the commission should be looking at the transmission projects “more holistically” and that the requested flexibility in the financing arrangements is too lax.

“It’s requesting flexibility to modify without prior commission approval the identity of the financing entities, payment terms and the amount financed,” Burman said. “I think we should be putting in some conditions or having them come back to us if they are going to be changing some of that. I understand the need for some flexibility, [and] I think we can address that as we move forward when we get into the more thorny issues and the other items that are not before us.”

The nearly $24 billion in combined CPNY and CHPE contracts fall under the new Clean Energy Standard Tier 4 category of renewable energy credits (RECs) set up to bring renewable energy into the city by the commission, which set a Feb. 21 deadline for reply comments on the contracts.

CHPE said in its financing petition that it had withheld the expected amount of financing given certain competitive concerns, including bid preparation for the New York State Energy and Research Development Authority’s (NYSERDA) Tier 4 solicitation.

Given that the NYSERDA Tier 4 solicitation has concluded, with the project being one of two award recipients, CHPE said in a supplement to the petition that it “will seek to raise debt financing in an amount not to exceed $4.5 billion.”

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California Poised to Regain Tailpipe Emissions Authority

The Biden administration could be days away from restoring California’s authority to adopt tailpipe emission standards that are more stringent than federal standards.

Citing “multiple sources,” E&E News reported Tuesday that the EPA could reinstate California’s authority as soon as Wednesday of this week. An EPA spokesperson told CNN that the agency expects to issue a decision on the waiver “in the near future.”

The EPA press office didn’t immediately respond to NetZero Insider’s request for information on Thursday.

At issue is a federal Clean Air Act waiver granted to California most recently in 2013 that allowed the state to enforce its tailpipe emission standards for cars and light-duty trucks — as long as the standards are at least as stringent as those of the EPA — as well as a zero-emission vehicle sales mandate. The low-emission vehicle and zero-emission vehicle (ZEV) programs are included in the California Air Resources Board’s Advanced Clean Cars regulation.

Other states were allowed to adopt California’s tailpipe emission standards as an alternative to using federal emission standards.

But in September 2019, the Trump administration adopted The Safer Affordable Fuel-Efficient Vehicles Rule Part One: One National Program Rule (SAFE-1), which rescinded California’s ability to set its own standards.

Then, on his first day in office last year, President Joe Biden issued an executive order directing federal agencies to immediately review actions taken under the Trump administration. The SAFE-1 rule was one that Biden’s order called out specifically.

In April 2021, EPA announced it was reconsidering the previous administration’s withdrawal of California’s waiver. EPA Administrator Michael Regan said at the time that the 2019 action was “legally dubious.”

“I am a firm believer in California’s long-standing statutory authority to lead,” Regan said.

Advanced Clean Cars II

The possible reinstatement of California’s ability to regulate tailpipe emissions comes as the California Air Resources Board (CARB) expects to roll out a new version of its emissions regulation.

Known as Advanced Clean Cars II, the new rule would apply to cars and light-duty trucks starting with model year 2026. CARB expects to finalize the regulation this year. (See CARB Preparing Full Course of ZEV Rules for 2022.)

As of this month, 17 states and the District of Columbia have adopted California’s low-emission vehicle regulations. Most of those have also adopted California’s ZEV regulation.

And other states may soon join the list. The New Mexico Environmental Improvement Board has scheduled a public hearing on May 4 to consider the proposed Clean Cars New Mexico regulation.

Nevada’s clean cars regulation, adopted in October, notes that the state will not enforce the regulation until the EPA reinstates California’s waiver or issues a new one.

California’s Response

In response to the EPA’s decision to rescind California’s waiver, CARB announced in 2019 that a group of automakers — Ford, Honda, BMW of North America and Volkswagen Group of America — had agreed on voluntary measures to reduce emissions. The framework included annual reductions of vehicle greenhouse gas emissions through the 2026 model year and steps to promote the transition to electric vehicles.

In addition, a California-led coalition quickly challenged in court EPA’s action to rescind the waiver. Litigation in that case was stayed while the current EPA reconsiders the waiver, according to a July release from California Attorney General Rob Bonta.

Bonta was joined by attorneys general from 20 other states and the District of Columbia along with representatives of several cities in sending a letter to EPA in July. The letter asks the agency to restore California’s waiver and rescind a previous determination that Section 177 of the Clean Air Act does not authorize other states to adopt California’s greenhouse gas standards for passenger cars and light trucks.

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Inslee Plugs Washington Buildings Bills at Forum with Gore, McCarthy

Gov. Jay Inslee on Wednesday urged constituents to lobby Washington legislators to drum up extra votes for two bills addressing the carbon footprints of buildings in the state.

Inslee was speaking at a virtual town hall that also featured former Vice President Al Gore and White House National Climate Adviser Gina McCarthy. The governor told watchers to call their legislators: “I need one vote each on a couple of bills right now.”

While it was not apparent how many people tuned in to the town hall, a moderator said that roughly 500 questions were submitted for Inslee, Gore and McCarthy. The meeting lasted about 50 minutes and only four questions were presented.

Inslee was stumping for Senate Bill 5722 and House Bill 1770.

Sponsored by Sen. Joe Nguyen (D), SB 5722 calls for the state’s Department of Commerce to set draft standards to trim carbon for buildings ranging from 20,000 to 50,000 square feet by Dec. 1, 2023. A 2019 law already addresses the carbon footprints of buildings that are greater than 50,000 square feet, which number about 10,000 in the state. (See Rent Provision Sparks Pushback on Wash. Buildings GHG Bill.)

Nguyen’s bill has already passed the Senate along party lines but appears to lack support from some Democrats among the party’s 57-41 majority in the House.

HB 1770 would require new residential and nonresidential buildings to reduce their energy consumption to 70% below the 2006 state energy code baseline by 2031 and 80% below the baseline by 2034 — as well as be equipped for solar panel placement. Introduced by Rep. Davina Duerr (D), the bill passed the House 51-47, with six Democrats voting against it.

Both bills are part of Inslee’s climate change legislative agenda for the 2022 session. (See Inslee Unveils $626M Climate Legislation Wish List.)

Most of Wednesday’s town hall functioned as a pep talk session by Inslee, Gore and McCarthy.

“We’re in the early stages of a sustainability revolution,” Gore said, later adding, “I think we’re at the political tipping point on the climate crisis.”

McCarthy and Inslee said states are better suited than the federal government to try new approaches to combat global warming. “We can advance the ball where the federal government cannot. We can do things that are unique to our circumstances,” Inslee said.

Gore contended that global warming would halt three to five years after the world reaches carbon neutrality. “It’s like a switch that can be flipped,” he said. The former vice president did not elaborate on any studies that backed up his contention.

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Powhatan Energy to Declare Bankruptcy

Powhatan Energy Fund will file for Chapter 7 bankruptcy, a company representative said Thursday, effectively ending more than a decade of litigation and legal moves with FERC over a high-profile market manipulation case in PJM.

In an email to RTO Insider, Powhatan co-founder Kevin Gates said the Pennsylvania-based money management firm that once participated in PJM markets “does not have enough money to continue to litigate with the FERC over simple spread trades that took place almost 12 years ago” and decided to declare bankruptcy, unwinding the firm. The bankruptcy documents were not yet filed as of Thursday evening.

In 2015, FERC ordered Powhatan and one of its traders to to pay $34.5 million in penalties and disgorged profits. The commission accepted the Office of Enforcement’s findings that the company and trader Houlihan “Alan” Chen violated anti-manipulation rules by making riskless back-to-back up-to-congestion (UTC) trades to profit on line-loss rebates (IN15-3). (See FERC Orders Gates, Powhatan to Pay $34.5 Million; Next Stop, Federal Court?)

In July of that year, the commission filed suit in the U.S. District Court for the Eastern District of Virginia to request an order affirming FERC’s orders assessing civil penalties, leading to several years of motions, countermotions and orders. Powhatan chronicled the legal back-and-forth on its website.

“We’ve already paid our attorneys many millions of dollars and simply do not have another million dollars to continue to defend ourselves from FERC’s meritless assault,” Kevin Gates said in the email.

The Case

Chen, who conducted the trades, began trading UTCs in 2007, after leaving Merrill Lynch, where FERC said he studied UTCs as a tool for physical and financial transactions.

Initially, Chen’s trades were based on market fundamentals and models he developed using a “careful, low risk approach of what he called ‘directional bets,’” FERC said. Most bids were under 100 MW, and his profitability depended on favorable price spreads.

In October 2009, after discovering he was receiving line-loss rebates, Chen switched to a strategy designed to capture increased volumes of rebates, FERC said.

His strategy changed again after suffering a $176,000 loss on May 30, 2010, when one leg of a trade saw an unexpected price spike. Following the loss, Chen switched to a round-trip trading strategy between the same two points (A-to-B, B-to-A) that FERC said made the underlying trades effectively riskless.

FERC sought penalties only for what it called the “manipulation period,” from June 1 to August 3, 2010, when Chen stopped the trading after receiving a warning from PJM Market Monitor Joe Bowring.

FERC began investigating Chen and Powhatan, with Chen and the Gates brothers responding to FERC data requests and sitting for depositions while their lawyers sparred with FERC attorneys and provided affidavits from an economist and an attorney supporting their defense.

In October, FERC issued a consent agreement with Chen, with Chen agreeing to disgorge $600,000 to PJM.

Gates’ Response

In 2015, Kevin Gates told RTO Insider that he rejected FERC’s offer to enter settlement discussions after he, his brother and Chen had responded to data requests and sat for depositions while their lawyers continued to spar with the agency. In a Feb. 18 email, Gates said the company subsequently attended “like three court-mandated settlement discussions,” none of which were productive.

The company did propose a settlement with FERC last June, which the commission turned down.

“Even though FERC’s investigation began 4,201 days ago, we weren’t even able to complete discovery as they threw up every possible roadblock they could think of to drag this case out and bleed us of resources,” Gates said.

Gates said FERC “essentially has an unlimited budget” to litigate cases and is “happy to spend other people’s money to promote their own agenda.” He said FERC’s “modus operandi” is to use litigation and their power to “extract massive, headline-grabbing settlements” from individuals and companies that don’t want to engage in their defense in court.

“We suspect this will make the FERC happy,” Kevin Gates wrote. “They have never sought the pursuit of justice, but rather used the administrative process and the legal system as a cudgel with which to bully us. FERC is part of the reason that citizens are losing faith in our government and a demonstration that bureaucrats sometimes deserve their worst stereotypes.”

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Rate Hikes Prompt Concern in California

The California Public Utilities Commission is questioning how much more ratepayers can stomach after approving back-to-back $1 billion rate increases for Pacific Gas and Electric and substantial rate hikes for the state’s two other large investor-owned utilities.

The increases were mostly driven by high natural gas prices and FERC transmission-rate requirements, among other factors, commissioners said.

“We’ve seen significant rate increases in each of the three major investor-owned utility service areas in the last few months,” Commissioner Darcie Houck said Feb. 10 before “reluctantly” approving the second major rate hike to hit PG&E customers since January. “Ratepayers have justifiably voiced concerns and objections to these rate increases.”

“We as a commission must carefully consider what and whether ratepayers can withstand regarding further rate increases, and we need to explore innovative methods to help curb rate increases and to protect the most vulnerable Californians,” Houck said.

The CPUC has scheduled an en banc hearing on utility rates for Feb. 28 and March 1 intended to examine proposals to control costs and mitigate rates. The two-day session follows a similar hearing last year attended by CAISO governors, state energy commissioners and legislative leaders, all concerned with spiraling costs. (See Calif. Worries High Rates Could Hurt Climate Efforts.)

The increases that took effect in January and others that start in March will worsen the situation, CPUC commissioners said.

In PG&E’s case, the CPUC approved a $769 million increase to the utility’s Energy Resource Recovery Account (ERRA) and a $358 million addition for ERRA under-collection in 2021, adding more than $1.1 billion to PG&E’s 2022 revenue requirement.

It will result in a nearly 11% rate hike for residential customers, averaging $16.37 per month, and larger increases for commercial and industrial users.

The changes, approved Feb. 10, take effect March 1.

“An industry and worldwide increase in natural gas commodity prices in 2021 and into 2022 has increased costs and is a main contributor to the increase approved today, which allows PG&E to recover from ratepayers the costs PG&E incurred to purchase power for customers in 2021 and forecasted costs for power in 2022,” the CPUC said in a statement following the decision.

The CPUC said it could re-examine the decision later this year if gas prices fall.

The new increase came on top of an 8% rate hike that took effect Jan. 1, averaging $11.29/month for PG&E residential customers.

The main drivers were a $671 million increase in FERC-approved transmission rates and a $284 million increase in PG&E’s general rate case for program costs, the CPUC said. The commission also granted PG&E $173 million in additional revenue to cover losses from unpaid bills during the pandemic and additional funds for wildfire insurance premiums.

“Ratepayers in PG&E territory have had a particularly difficult year and are questioning these increases along with safety concerns, given the many catastrophic wildfires suffered over the years,” ignited by PG&E equipment, Houck said.

“In addition to energy fuel costs rising, we are also facing challenges to grid infrastructure upgrades and ensuring sufficient resources to meet our clean energy goals,” she said. “All of these items require investment. All this said, ratepayers are not an unlimited source of funds to cover any and all costs.”

SCE, SDG&E

For Southern California Edison, the CPUC approved a January rate increase of 2.9%, working out to an average monthly bump of $3.99 in residential bills.

The causes included the addition of $385 million to SCE’s general rate case for wildfire mitigation work, including vegetation management, installing covered conductor, and upgrades to SCE’s transmission and distribution grid. The CPUC also authorized an increase of $238 million for transmission capital, operation and maintenance costs in 2022, based on prior approval from FERC.

SCE’s purchase of $1 billion in liability insurance, as required by state law, contributed to the rate hike, the CPUC said.

CPUC-approved increases that take effect in March reflect high natural gas prices, the recovery of $401 million in wildfire prevention costs and $77 million for unpaid bills during the pandemic.

In December, the CPUC approved $1.2 billion in rate recovery for SCE’s procurement of 536 MW of energy storage for summer reliability. About $85 million of that will be collected in 2022, the CPUC said.

Starting in March, SCE residential customers can expect an additional 7.7% bill increase, adding $11.48 a month on average.

Between the January and March rate hikes, SCE residential customers will be paying nearly 11% more for electricity this year, or about an extra $12.50 per month.

San Diego Gas and Electric residential bills rose by 11.4% in January because of a $273.5 million boost to the utility’s revenue requirement, mostly based on high gas prices, and $38.5 million for transmission costs authorized by FERC, the CPUC said. Insurance premiums of $65 million also contributed to the higher rates.

CPUC President Alice Reynolds and commissioners Genevieve Shiroma and Clifford Rechtschaffen also expressed concern about rising electricity costs.

Rechtschaffen said the CPUC must continue working on the issue, including at the upcoming en banc hearing.

“We’re looking for innovative ideas to improve affordability, especially for low- and moderate-income customers,” Rechtschaffen said. “We really need to dig deeply into some of these solutions.”