Page 445 – RTO Insider

July 29, 2022November 30, 2023

FERC Proposes Allowing RTOs to Share Credit-related Info

WASHINGTON — FERC on Thursday proposed allowing RTOs and ISOs to share credit-related information about market participants, fulfilling one of the main requests the grid operators made at a technical conference last year (RM22-13).

The Notice of Proposed Rulemaking, approved unanimously at the commission’s monthly open meeting, would require the grid operators to revise their tariffs to eliminate confidentiality provisions that prevent them from sharing such information. They would also be allowed to use received information for the same purposes for which they use information from their own market participants.

Allowing this information sharing “could improve the accuracy of credit exposure and risk assessments across multiple electric power markets,” the commission said in a statement. “It also could enable market operators to respond to credit events more quickly and effectively, thereby minimizing the overall risks of unexpected defaults by market participants.”

At a technical conference in February 2021, RTO credit risk officials told FERC that although they meet monthly with their counterparts to share best practices, confidentiality rules prevent them from sharing market participant-specific information, even if the participant may pose a credit risk in multiple markets. (See RTOs: Let Us Share Trading Info.)

The commission agreed this is a problem.

“Negative credit events affecting a market participant’s credit standing in one market may impact its credit standing in other markets,” FERC said in its proposal. “An RTO/ISO that cannot obtain market participants’ credit-related information arising from their activities in other organized wholesale electric markets may not be able to fully protect its organized wholesale electric market from mutualized default risk.”

The commission also specified that information sharing must not be predicated on a market participant’s prior notice or consent. “A market participant facing financial difficulty would have little incentive to consent to credit-related information sharing,” it said.

Comments on the NOPR are due 60 days after publication in the Federal Register.

Collateral Requirements

The technical conference stemmed from PJM’s debacle with GreenHat Energy, which FERC accused of defrauding the RTO by acquiring a massive 890 million-MWh portfolio of financial transmission rights with only about $550,000 in collateral. When it defaulted on the portfolio in 2018, its three principals made off with $13 million and left PJM members holding a $179 million bag, FERC said in a January lawsuit after the company failed to pay $242 million in fines. (See FERC Levies $242M in Fines on GreenHat, Owners.)

FERC cited GreenHat in a second unanimous order Thursday requiring CAISO, ISO-NE, NYISO and SPP to show cause as to why they shouldn’t revise their tariffs to include provisions ensuring FTR market participants maintain sufficient collateral (EL22-62, et al.).

The commission said that after considering remarks at the technical conference and comments in that docket, it believes “that two specific practices may be particularly critical to effectively managing credit risk for FTRs”: a mark-to-auction mechanism and a volumetric minimum collateral requirement. Three of the grid operators cited in FERC’s order already implement one practice, but not the other; CAISO implements neither.

The first practice requires that participants maintain sufficient collateral to support the change in value of the FTR positions they hold based on the most recent auction prices for those FTRs. The commission noted that GreenHat’s losing positions went unnoticed by PJM because the RTO used historical FTR values. Since the company’s default, PJM — along with ISO-NE, MISO and NYISO — revised their tariffs to implement mark-to-auction mechanisms.

“While CAISO has limited opportunities to update the collateral requirements of [congestion revenue rights], it does not have a robust mark-to-auction FTR collateral requirement similar to what has been adopted recently in other organized wholesale electric markets,” FERC said. “SPP’s current TCR [transmission congestion rights] collateral requirements also do not include updating of collateral requirements based on the current value of a market participant’s TCR portfolio for all TCR positions.”

In addition, a minimum collateral requirement based on volume ensures that a market participant is required to cover potential defaults even when it has offsetting positions, FERC said.

“In some RTOs/ISOs, market participants are allowed to net FTRs with negative collateral requirements against FTRs with positive collateral requirements within the market participant’s portfolio, which can lead to large, risky FTR portfolios that require little or no collateral,” FERC said. “This can be a problem if future congestion is significantly different than historical congestion because the collateral held by the RTO/ISO may be insufficient for a portfolio’s risk.”

MISO, PJM and SPP all instituted volumetric minimum requirements after GreenHat’s default. “While [CAISO, ISO-NE and NYISO] establish minimum capitalization and participation requirements, they appear to lack any volumetric minimum collateral requirement that scales with a participant’s FTR portfolio to ensure participants cannot minimize their required collateral without correspondingly reducing their risk,” FERC said.

CAISO, ISO-NE, NYISO and SPP must file their responses within 90 days.

July 29, 2022

Xcel Sees Benefits in $3.2B Transmission Opportunities

Xcel Energy executives Thursday praised both the MISO long-range transmission plan (LRTP) and late-breaking agreement in D.C. over the $670 billion Inflation Reduction Act, telling financial analysts both will help the company add 10 GW of renewable energy in its resource plans.

CEO Bob Frenzel said the company is “excited about our transmission expansion opportunity” and expects a $1.2 billion investment for six projects in the LRTP’s $10 billion first tranche of projects. Several projects in Xcel’s Wisconsin footprint have been identified as upgrades, which will keep them in the company’s hands. (See FERC Allows MISO to Exclude Tx Projects from Competition.)

Combined with Xcel’s Colorado Power Pathway — a $1.7-$2 billion, 560- to 650-mile project with regulatory approval — and the transmission needs in its Minnesota resource plan, the company now has about $3.5 billion in large-scale transmission projects.

Frenzel said that will help Xcel add to the renewables it needs for its Minnesota and Colorado resource plans and reach its target of 80% carbon reductions by 2030.

The Minneapolis-based company also reacted positively to the deal reached Wednesday between Senate Majority Leader Chuck Schumer (D-N.Y.) and Sen. Joe Manchin (D-W.Va.) on a climate package that could be up for a reconciliation vote. (See Schumer, Manchin Reach Climate Deal.)

“It appears to include nearly all the broader clean energy tax credits, including new and extended tax credits for wind, solar, hydrogen storage and nuclear,” Frenzel said. “The energy provisions included in the act would provide substantial customer benefits and help enable our clean energy transition while keeping our customer bills affordable. There’s still a lot of twists and turns that can happen in Washington, but we’re optimistic that the bill could become law.”

Xcel reported second-quarter earnings of $328 million ($0.60/share), slightly above last year’s second-quarter earnings of $311 million ($0.58/share). Operating earnings came in at $0.60/share, in line with the Zacks Consensus Estimate.

The company’s share price closed at $72.21 Thursday, up 2.8% from the previous close.

July 29, 2022June 14, 2023

SPP Regional State Committee Briefs: July 25, 2022

SPP’s Regional State Committee on Monday approved its Cost Allocation Work Group’s recommendation to approve a congestion-hedging solution for three DC ties that will connect the RTO’s Eastern and Western interconnection footprints.

The DC ties are owned by members of SPP’s Western Energy Imbalance Service market, providing up to 510 MW of capacity for RTO operations. Other DC ties could be added as the grid operator continues its Western expansion.

The DC Tie Solution Group developed the recommendations earlier this year in a white paper. It said the ties provide a necessary link to “facilitate single market operations” between the two interconnections and to ensure the best use of the facilities and maximum market benefit.

Dana Murphy, OCC | SPP

The RSC has agreed that a DC tie cost-allocation methodology should be developed because of their unique operational characteristics and their market functionality. According to the white paper, the AC portion of the transmission-service paths that cross a specific DC tie will be awarded auction revenue rights (ARRs) and transmission congestion rights (TCRs) as a single path source to sink and then settled in multiple parts. The rights will be settled in two stages, with the AC portions settling in their respective interconnections. Day-ahead market congestion rent across the DC tie in both stages will be an option style, with the AC portions remaining as obligations.

The solution group recommends a four-year transition period. In the first four years, DC tie congestion settlement is removed from the TCR market. After that, the DC tie settlements process moves to SPP’s existing TCR market approach. TCR holders will be compensated for a specific tie’s congestion based on the awarded TCR megawatt amount.

Legacy facilities’ annual transmission revenue requirement will remain in their respective local transmission zone and will also remain part of the zone’s network and point-to-point rates. However, increased use of the DC ties will result in increased maintenance costs, the solution group said, with increased costs being borne fully by the tie owner’s zone unless cost recovery mechanisms are put in place.

The white paper creates two new revenue recovery mechanisms, an access charge and an incremental market efficiency use (MEU) charge, to recognize beneficiary-pays principles and recover increased operational costs due to market operations.

CAWG to Continue Safe Harbor Study

The committee directed the CAWG to spend at least another quarter exploring further changes to SPP’s three safe harbor criteria and its $180,000/MW limit and bring back the results to its October meeting.

The RSC’s review of safe harbor criteria is its first since 2018. A 2020 study was canceled in 2019 following the regulators’ decision to conduct in-depth safe harbor reviews every five years. (See “Regulators Cancel 2020 Safe Harbor Review,” SPP Regional State Committee Briefs: July 29 & Aug. 5, 2019.)

The reviews are intended to determine whether modifications should be made to the thresholds used to determine what project costs should be borne by the load-serving entities (LSEs) making long-term transmission service requests (TSRs).

SPP’s aggregate transmission service study process combines into a single study all long-term point-to-point and designated network resource requests received during a specified time period. The RTO splits the costs of transmission projects between the entire SPP footprint and the LSEs purchasing transmission service for designated resources — those used to meet the LSE’s capacity margin requirement.

The safe harbor exempts LSEs from upgrade costs when a TSR meets the aggregate studies’ waiver criteria, which include:

wind generation not exceeding 20% of designated resources;
a minimum five-year term for designated network resources TSRs; and
designated resources not exceeding 125% of forecasted load.

The CAWG will bring back any modifications to the criteria or the amount. Several states have expressed an interest in further evaluating the 125% load and 20% wind criteria, regulatory staff said.

Travel Costs Increase Budget

The RSC approved a proposed budget for 2023 that reflects rising travel costs, despite a reduction of in-person meetings from four to two.

The total budget of $424,500 includes $270,00 for travel and meetings, an almost 57% increase from last year.

The committee is more than $123,000 under this year’s budget. Members have spent more than $37,000 of a budgeted $86,000 on travel and meetings.

Members, who will only meet twice in person this year, discussed the possibility of a third face-to-face meeting next year. Minnesota’s John Tuma, sitting outside in what he described as 76-degree temperatures and mild humidity, suggested the RSC gather in the Minneapolis-St. Paul area for its next July meeting.

Fiegen to Chair Nomination Committee

Members selected South Dakota’s Kristie Fiegen to chair the RSC’s Nomination Committee, where she will be joined by Arkansas’ Ted Thomas and Missouri’s Scott Rupp.

They will be responsible for bringing the 2023 proposed leadership slate to the RSC’s October meeting. They will also have to select at least one new member for the committee, as Oklahoma’s Dana Murphy is term-limited after this year.

July 29, 2022November 30, 2023

FERC NOPRs Would Require ‘Candor,’ Improved Accounting for Renewables

FERC issued two rulemakings Thursday that would impose a “duty of candor” in communications and set new accounting regulations for renewables.

The Notice of Proposed Rulemaking that would amend the Uniform System of Accounts (USofA) to create new accounts for non-hydro renewables was approved unanimously, while the NOPR to address the current “patchwork” of requirements regarding truthful communications (RM22-20) moved forward on a 4-1 vote, with Commissioner James Danly dissenting.

The latter would require truthful communications with the commission, RTOs/ISOs, their market monitors, NERC and its regional entities, and other companies under FERC jurisdiction in the electric, natural gas and oil industries and markets, including transmission or transportation providers.

Gabe Sterling, FERC Office of Enforcement | FERC

“In the past, different duties of candor have been adopted by the commission governing specific types of communications from certain organizations and persons and related to discrete areas of the commission’s jurisdiction,” Gabe Sterling, of the Office of Enforcement, said during a presentation at FERC’s open meeting. “This existing patchwork of requirements is insufficient to encompass all of the situations in which the commission must be assured that it is receiving accurate communications that are necessary for it to adequately conduct its regulatory oversight.”

The proposal, intended to capture communications that have not been explicitly included in existing requirements, is based on 18 C.F.R. section 35.41(b), approved nearly 20 years ago to govern communications by electricity sellers with market-based rate authority.

It would require covered entities to submit “accurate and factual information and not submit false or misleading information or omit material information.”

“We cannot do our job if we’re getting bad information … which arguably, we’ve gotten at times,” said Chair Richard Glick.

“It doesn’t really seem like a lot to say you have to tell the truth when you’re coming to the commission,” he added. “What blows my mind is that we actually don’t require that in many instances.”

As with section 35.41(b), entities would not be accused of violations if they can demonstrate due diligence to prevent false statements.

That wasn’t enough protection for Danly, however, who said the rulemaking was too expansive and vague.

He said the rule lacks the “ordinary safe harbor provisions” to protect First Amendment rights and that the commission failed to define “due diligence” or potential penalties for violations.

“The number of people that are covered by this is huge,” he said. “I am worried that people are going to be reticent to comment [negatively on the NOPR] because [it] would be construed as some kind of a declaration that they don’t believe that truth is necessary.”

Commissioner Mark Christie — a Republican, like Danly — said his colleague’s concerns were misplaced.

“I’m not worried at all about anybody’s reluctance to comment,” he quipped. “If people are queasy about commenting about the truth, all they’ve got to do is just hire their lawyer to do it.”

Commissioner Allison Clements also dismissed Danly’s criticism, saying “we are not going down the extreme path that” he suggested.

“I take seriously what Commissioner Danly said,” Commissioner Willie Phillips said. “We have to right-size it. I think the team has thought about that in the questions that they have proposed, and I too look forward to the comments.”

Those comments will be due 60 days after publication in the Federal Register.

In his dissent, Danly said the proposed rule could result in legal action against a landowner angry about construction noise who “says something like ‘I’ve never heard such a racket,’ but in fact she had heard such a racket at a Poison concert in 1988? Absurd? Yes. Duty of candor violation? Also, yes.”

In his press conference after the meeting, Glick said he became concerned about the issue when it came up in a 2019 order regarding connected entities (Order 860, RM16-17). “I was just appalled that we didn’t move forward with [the duty of candor] part of the order; that we couldn’t even require people to tell the truth,” he said. (See FERC Reduces MBRA Data Requirements.)

He conceded that “there’s a lot of detail that has to be worked out.”

“We’re asking for comments; we’re looking forward to reading those comments and making changes based on those comments. But at least let’s try to move forward with something,” he said.

Anyone found violating the rule could be subject to Enforcement action. But the NOPR said “it is not the commission’s intention to investigate or penalize all potential violations of the proposed regulation. As a general matter, we do not intend to penalize inadvertent errors, especially those of limited scope and impact.”

Renewable Accounting Rule

The second rulemaking (RM21-11) would be the latest in a number of revisions that the USofA has received in response to changing technology, laws and market conditions since its creation by FERC’s predecessor, the Federal Power Commission.

The NOPR, which resulted from a January 2021 Notice of Inquiry, proposes four changes:

the creation of dedicated production accounts for wind, solar, and other non-hydro renewable assets. Because the current USofA does not have unique accounts for non-hydro renewables, utilities characterize them as “other production.” The new categories will result in more uniform and transparent reporting, FERC said.
the creation of a single class for energy storage accounts to end the need for utilities to reallocate costs between production, transmission and distribution accounts based on usage of the assets. The commission said the current practices are impractical and a significant burden on the filing entities.
the codification of the accounting treatment of renewable energy credits (RECs) and similar financial instruments. It would result in the creation of dedicated inventory accounts for RECs, consistent with previous commission guidance on emissions allowances.
the creation of dedicated accounts for computer hardware, software and communications equipment. The NOPR seeks comment on whether FERC should also create such accounts for natural gas pipelines, oil pipelines and service companies.

Kimberly Horner, FERC Office of Enforcement | FERC

Kimberly Horner, of the Office of Enforcement, said the new accounts for renewables “would provide utilities with the ability to report in a more transparent manner to better inform the ratemaking process and also inform the public of their investments in these technologies.”

She said the current handling of energy storage assets is burdensome because the cost of the same asset must be reallocated among the different accounts based on their usage, which frequently changes. “The new proposed accounting would instead propose one account, and it would reduce the burden by allowing for the cost of the same asset to be recorded in one account, rather than continuously reallocated,” she said.

In addition to the proposed changes, the NOPR seeks comment on whether FERC’s chief accountant should issue guidance on accounting for hydrogen applicable to public utilities and licensees and natural gas companies.

Comments are due 45 days after publication in the Federal Register.

Michael Brooks contributed to this article.

July 29, 2022

What’s in the Inflation Reduction Act, Part 1

The text of the Inflation Reduction Act (IRA) of 2022 released by Senate Democrats on Thursday carries the same number (H.R. 5376) as the ill-fated Build Back Better Act passed by the House of Representatives last November, but its $670 billion falls far short of the original $2.2 trillion.

“Look, this bill is far from perfect. It’s a compromise,” President Biden said Thursday. “But it’s often how progress is made: by compromises.” He hailed the bill, rescued by Senate Majority Leader Chuck Schumer (D-N.Y.) through negotiations with Sen. Joe Manchin (D-W.Va.), as the strongest that could be passed right now to lower inflation and advance clean energy.

Energy industry leaders and advocates had already welcomed the IRA’s $369.75 billion for clean energy on Wednesday, after which they started digging into the bill’s 725 pages to parse out how that money is allocated and will be spent. (See Schumer, Manchin Reach Climate Deal.)

Reflecting Manchin’s thinking on the U.S. energy transition, the bill leans toward a broad definition of clean energy technologies, encompassing solar and wind, as well as nuclear, green hydrogen and carbon capture.

For example, in its provisions on rebates for zero-emission vehicles, mentions of “qualified plug-in electric motors” have been changed to “clean vehicles,” allowing fuel-cell vehicles to qualify for the incentives.

Similarly, investment and production tax credits for solar and wind are extended through the end of 2024, after which they become technology-neutral clean energy credits, according to an analysis from the American Council on Renewable Energy (ACORE).

Experts and advocates continued to comb through the bill on Thursday, nailing down details, but here are some key takeaways.

Energy Efficiency

Energy efficiency is a big winner. The top line numbers in the bill summary provided by Senate Democrats include $9 billion in rebates to help low-income consumers perform energy-efficient home retrofits and electrify home appliances.

The summary also mentions tax credits for energy-efficient home improvements, which the bill spells out in more detail. For example, tax credits for installing energy-efficient windows or skylights top out at $600 per year, while credits for heat pumps and biomass stoves and boilers go up to $2,000.

Such “historic investments … will reduce energy waste, cut costs for homes and businesses and slash greenhouse gas emissions,” said Steven Nadel, executive director of the American Council for an Energy Efficient Economy. “It would enable major efficiency and electrification upgrades in millions of homes and buildings to save energy and improve comfort and health, especially for low- and moderate-income households.”

EVs

Manchin has often criticized EV incentives as rewarding the wealthy, who don’t need rebates to afford new EVs. While the IRA does provide rebates for both new and used EVs, it also limits which cars and consumers will be eligible.

Rebates for new EVs, topping out at $7,500, will only be available for passenger vehicles that cost $55,000 or less, while the cap for electric SUVs, pickup trucks and vans will be $80,000. Income caps for prospective buyers range from $300,000 for couples filing joint tax returns to $150,000 for individuals.

The law also contains a $4,000 rebate for “previously owned” EVs, which it defines as vehicles “the model year of which is at least two years earlier than the calendar year in which the taxpayer acquires such vehicle” — so, no rebates for buying a year-old EV. The cap on sales price in this case is $25,000, and the rebate is only available on the first resale of the EV; that is, from its original owner.

The income caps for the used car rebates are $150,000 for couples and $75,000 for individuals.

Supply Chain and Transmission

The law also supports the buildout of a clean energy supply chain with new tax credits for advanced manufacturing of a range of solar, wind, storage and inverter components. The bill summary lists $10 billion for investment tax credits for “clean technology manufacturing facilities, like facilities that make electric vehicles, wind turbines and solar panels.”

Christian Roselund, senior policy analyst at Clean Energy Associates, said the tax credits for manufacturing could have a big impact on the solar supply chain in the U.S. “One of the fundamental challenges to onshoring U.S. solar manufacturing has been cost and specifically [operating expense] costs,” Roselund said. “It’s been the cost of not just building factories … but the cost of running factories.”

The bill provides a detailed list of tax credits for specific technologies. Solar cells, whether thin film or crystalline photovoltaic, will be able to claim credits of 4 cents/W, while panels will be eligible for credits of 7 cents. At present, the capacity for individual rooftop panels is about 350 to 375 W.

Industry advocates who lobbied for a transmission investment tax credit will be disappointed, according to ACORE, but it does provide:

$2 billion in direct loans for construction and modification of transmission deemed in the national interest;
$760 million in grants for permitting and siting and for economic development in communities with transmission builds; and
$100 million for modeling and analysis.

July 29, 2022December 13, 2023

Texas RE Warns Utilities Not to Wait on CIP Compliance

With NERC’s newest critical infrastructure protection (CIP) reliability standards set to take effect later this year, staff at the Texas Reliability Entity on Thursday warned that utilities should already have a plan in place for implementing their new cyber supply chain security requirements.

FERC approved the three standards in March 2021 after they were developed as part of Project 2019-03 (Cybersecurity supply chain risks). (See FERC OKs Updated Supply Chain Standards.) The following standards were affected:

CIP-005-7: Cybersecurity — Electronic security perimeter(s)
CIP-010-4: Cybersecurity — Configuration change management and vulnerability assessments
CIP-013-2: Cybersecurity — Supply chain risk management

The biggest change from the currently effective standards — CIP-005-6, CIP-010-3 and CIP-013-1 — is the inclusion of electronic access control or monitoring systems (EACMS) and physical access control systems (PACS). FERC ordered the EACMS revisions when it approved the previous standards in 2018, and NERC subsequently added PACS to the project’s scope. (See FERC Finalizes Supply Chain Standards.)

In a webinar on the new standards, Kenath Carver, Texas RE’s director of cybersecurity outreach and CIP compliance, noted that they represent a minimum with which some entities are already compliant, either because they proactively implemented the EACMS and PACS requirements when the standards were approved or because they have always considered these systems vulnerable and took precautions independently of the CIP standards. But he warned listeners who haven’t yet taken the necessary steps not to wait.

“For some of you, we’ve seen in our small group advisory sessions or in our one-on-one sessions, that folks have [applied] the supply chain requirements to some of these things, even though the effective date is not here yet. For others, maybe you haven’t,” Carver said. “So this is going to be a pretty big lift because this is a lot more applicable cyber assets that you now have to worry about.”

Carver reminded attendees that both EACMS and PACS “by their nature … are an attack vector” because they grant direct access to a utility’s control systems, through which a malicious actor could potentially carry out a disruption to service. He also pointed out that the standards intentionally cast a “very broad web,” leaving the definitions of pertinent assets intentionally vague in order to ensure they are applied widely and have as large an effect as possible.

As an example of the standards’ wide applicability, Carver observed that under CIP-005-7’s new supply chain requirement a utility must “implement one or more documented practices” for determining whether a vendor’s attempt to connect to its systems remotely is authentic, and to terminate such connections and control their ability to reconnect. This might not sound like a big ask, but utilities may soon need to be able to provide such documentation for potentially hundreds of interactions per day from multiple vendors.

“If you have what you feel is authenticated vendor-initiated remote connection … you really have to be able to explain your definition and how that meets the security objective of this piece here, especially if a vendor is somehow connecting to a PACS or EACMS,” he said.

The standards will take effect Oct. 1.

July 28, 2022

FirstEnergy Spending $1.5B on Transmission Projects this Year

The return on investments over the last five years to upgrade its transmission system helped FirstEnergy’s second-quarter earnings, the company reported Wednesday.

FirstEnergy currently is overseeing more than 1,000 transmission upgrades, at a budgeted cost of $1.5 billion and part of a $7 billion plan that began in 2018.

“Our transmission business continues to be one of the focal points of our strategy,” CEO Steven Strah said during a teleconference with analysts. “Our Energizing the Future program has a relentless focus on reliability improvements for our customers.

“We began the investment program in the ATSI region in 2014. And since that time, we have seen a 53% reduction in the interruptions to customers caused by transmission outages, a 49% decrease in transmission line outages and an 88% improvement of our protection systems. We’re striving to build on this success within ATSI and across our territory as we continue to expand this investment program.

“So far this year, we’ve completed important work across our footprint to reconfigure several substations, rebuild transmission lines, replace transformers and enhance network, cyber and physical security. These projects improve operational flexibility, upgrade the condition of equipment and enhance system performance,” Strah said.

A formula developed by FERC typically sets the rate of return on such necessary transmission projects around 9%, compensating a utility for the risk involved.

The company reported second-quarter net income of $187 million ($0.33/share) on revenue of $2.8 billion. That compares to net income of $58 million ($0.11/share) on revenue of $2.6 billion in the second quarter of 2021.

Although residential sales decreased 1.6% compared to the second quarter of last year, reflecting milder weather this past spring, commercial and industrial sales increased 1.9% and 2.4%, respectively, CFO Jon Taylor said. And for the first time, industrial sales were higher than pre-pandemic levels, he said, “reflecting strong recovery and growth in many sectors, including steel, fabricated metals, automotive and food manufacturing.”

The one concern in the otherwise upbeat earnings report is that expenses related to the performance of FirstEnergy’s pension plan in what the company calls a “bear market,” along with rising interest rates, could make the plan more expensive to fund, reducing net earnings.

July 28, 2022November 8, 2023

Study Finds Adding More Hydrogen to Natural Gas Raises Risks

A study commissioned by the California Public Utilities Commission has found that injecting more than small amounts of hydrogen into natural gas pipelines can increase leakage and degrade metal, raising questions about the safety of using existing gas infrastructure for decarbonization.

Advocates have suggested that blending higher amounts of renewably produced “green” hydrogen with natural gas could be a way to partially reduce the gas system’s carbon footprint while retaining the value of existing gas infrastructure. State lawmakers have expressed interest in the concept, with bills directing state energy agencies including the CPUC to study hydrogen’s potential.

As part of that effort, researchers at University of California, Riverside conducted a “Hydrogen Blending Impacts Study,” which the CPUC commissioned as part of its long-running rulemaking on renewable natural gas. Part four of that rulemaking, opened in November 2019, addresses standards for injection of renewable hydrogen into gas pipelines.

“This study provides additional insight into the possibilities and limits of California’s pipeline infrastructure as we explore options for supplying zero-carbon energy to hard-to-decarbonize applications,” CPUC Commissioner Clifford Rechtschaffen, the lead commissioner in the rulemaking, said in a July 21 news release accompanying the study’s release.

The 180-page study assessed operational and safety concerns related to injecting hydrogen into the existing natural gas pipelines at varied percentages.

The researchers found that hydrogen blends of up to 5% in the natural gas stream are relatively safe but that blending more hydrogen in gas pipelines can embrittle steel pipes and raise the risk of leaks.

“A primary concern of hydrogen blending with respect to pipeline durability and integrity arises from a hydrogen embrittlement phenomenon observed in many metals,” the study said. “Hydrogen embrittlement is defined as the process of strength and ductility reduction within a metal due to hydrogen induced damage, which makes it more brittle. Main mechanical properties of steel such as tensile strength, toughness and fatigue resistance are adversely affected by hydrogen embrittlement.”

Hydrogen blends above 5% could require modifications to gas appliances such as stoves and water heaters to avoid leaks and malfunctions, it said.

“This systemwide blending injection scenario becomes concerning as hydrogen blending approaches 5% by volume,” the study said. “As the percentage of hydrogen increases, end-use appliances may require modifications, vintage materials may experience increased susceptibility and legacy components and procedures may be at increased risk of hydrogen effects.”

Hydrogen blends of more than 20% carry a higher risk of permeating plastic pipes, increasing the risk of ignition outside the pipeline, the CPUC noted.

Plastics such as polyethylene “make up more than half of the pipe materials used in the natural gas distribution system,” the study said. Unlike steel, prior reports showed “no degradation [to plastics] by pure hydrogen … and little or no interaction between hydrogen gas and polyethylene.”

“The main concern with pipelines comprising of polyethylene is permeability to hydrogen, which may result in leakage of gaseous hydrogen,” it said.

About 65% of distribution pipelines are made of plastics and 35% are steel, it said.

Another concern identified by the study is that hydrogen has a lower energy content than methane and other natural-gas components, requiring more hydrogen-blended gas to produce the same amount of energy.

The study called for additional examination of hydrogen blending to ensure its safety, including demonstration projects under controlled, real world circumstances.

“As there are knowledge gaps in several areas, including those that cannot be addressed through modeling or laboratory scale experimental work, it is critical to conduct real world demonstration of hydrogen blending under safe and controlled conditions,” the study said.

The CPUC requested public comment on the study by Aug. 26.

“I look forward to party comments on hydrogen-methane blending and its role in decarbonization strategies,” Rechtschaffen said.

July 28, 2022June 14, 2023

Change to PJM Market Seller Offer Cap Falls Short

PJM’s proposal to change its market seller offer cap (MSOC) fell short of the two-thirds endorsement threshold Wednesday as load sector stakeholders expressed concern over its impact on capacity prices.

The proposal, which would ensure sellers are always able to represent the cost of their Capacity Performance (CP) risk when offering into the capacity auction, won only 60.4% support in a sector-weighted vote of the Markets and Reliability Committee following more than an hour of debate.

PJM proposed MSOC schedule (PJM) Content.jpg

PJM hoped to win stakeholder and FERC approval of the revised market seller offer cap (MSOC) in time for its next Base Residual Auction in December. | PJM

The rule change would set the MSOC at the greater of the CP quantifiable risk (CPQR) or net avoidable-cost rate (ACR) inclusive of CPQR.

PJM, which sponsored the proposal in response to requests from generators, said it would address circumstances in which a unit with a positive CPQR value has that cost offset by an otherwise negative net ACR, which could result in a $0 offer cap.

PJM had hoped to win stakeholder and FERC approval for the change effective with the 2024/25 capacity auction in December. After the vote, Adam Keech, PJM vice president of market services, said staff hadn’t had “real material discussions” on whether to recommend the Board of Managers file the proposal without stakeholder approval.

American Municipal Power’s Steve Lieberman said he was “extremely disappointed” with the way the issue was “shepherded” through the Resource Adequacy Senior Task Force, rejecting PJM’s characterization of it as a “narrow” change. (See “Stakeholders Wary of ‘Narrow’ Change to Market Seller Offer Cap,” PJM Markets and Reliability Committee Briefs: June 29, 2022.)

Lieberman said the proposal would be “a major change” to the Reliability Pricing Model and was proposed in response to the low prices in the last Base Residual Auction in June, when capacity prices dropped by one-third to almost one-half. (See PJM Capacity Prices Crater.)

Examples of market seller offer caps (MSOC) under current rules and under PJM’s proposal | PJM

He said AMP is willing to consider changes to the MSOC as part of a “holistic” review of capacity market rules.

PJM’s Pat Bruno said CPQR is defined in the tariff as part of ACR and must be “quantifiable and reasonably supported.”

Steve Lieberman, American Municipal Power | PJM

“It’s still supposed to reflect the market sellers’ evaluation of the risk,” he said.

Independent Market Monitor Joe Bowring said it is impossible to evaluate the impact of the CPQR change without understanding how PJM would interpret “reasonable support.”

“This is a very significant change to the concept of what the MSOC is,” he said. Removing a part of the ACR “simply is not logical and doesn’t make sense.

“There’s no issue that requires a short-term solution. We think this is a bad idea. It’s not narrow. It should be part of a broader package.”

Jeff Whitehead, of GT Power Group, said stakeholder concerns that the rule change would set a minimum capacity “floor” price would be addressed by PJM and IMM reviews of the generator filings.

“I don’t believe it does [create a floor. But] as long as it’s supported … it’s not inappropriate that a new floor would be created,” said Whitehead, who said he asked PJM to pursue the change.

“Unfortunately, a holistic approach went out the window with the MOPR,” he added, referring to FERC’s order effectively eliminating the minimum offer price rule for subsidized generation.

“This is a fair and simple reform, despite what the opponents are going to claim,” said Jason Barker, of Constellation. “People have said this is a response to the last auction. It’s not. This is a longstanding issue.”

Susan Bruce, representing the PJM Industrial Customer Coalition, said allowing market sellers to reflect their risks in their offers “is a concept that’s hard to say no to.”

But she said her group would oppose the change without more certainty over the CPQR definition. “We don’t know the size of the breadbox,” she said.

Carl Johnson, representing the PJM Public Power Coalition, said he could not recommend his members support the measure.

Greg Poulos, executive director of the Consumer Advocates of PJM States, said most of his members would not support the change because of the “piecemeal” nature of the proposal.

Erik Heinle, however, said the D.C.’s Office of the People’s Counsel would support the change, saying Whitehead and others had identified a “legitimate issue with the current construct.”

He noted that wind generators cleared 434 MW less in the last auction than the previous one, a drop of 25%. “We certainly recognize the impact of this rule change on intermittent resources that often have very low ACRs and very high CPQRs. That was a major part of our thinking on this issue,” he said.

Although he said more discussion is needed on the “parameters” of CPQR, he said his office is confident that the change wouldn’t undermine PJM and the IMM’s ability to prevent exercises of market power.

Bowring wasn’t so confident.

“There’s no good information on how high [the CPQR] could be or the impact on the clearing price without knowing PJM’s rules,” Bowring said. Expecting the IMM to prevent market power “cannot happen if the rules are bad.”

July 28, 2022November 15, 2023

Report: Maine Surpassed 10% by 2020 Emission Reduction Target

Decreased fossil fuel use helped Maine meet its 2020 greenhouse gas reduction target, according to a state Department of Environmental Protection report released Thursday.

The department’s analysis of the most up-to-date federal GHG emissions data through 2019 showed that Maine’s GHG emissions were 25% below 1990 levels, surpassing a reduction target of 10% below 1990 levels by Jan. 1, 2020.

Total estimated annual GHG emissions in Maine peaked in 2002 compared to 1990 levels and declined to below 1990 levels by 2009, according to the department’s Ninth Biennial Report on Progress Toward GHG Reduction Goals. Emissions increased slightly from 2013 to 2015, then continued to drop through 2019.

“A reduction in residual fuel oil consumption, 97% since 1990, is a large driver of the overall decline in GHG emissions,” the report said.

Included in the report are the state’s first CO₂ budget data, including details on sequestration by forests, fields and wetlands.

“It is essential for the creation and evaluation of emission reduction programs to take into account this more comprehensive view of carbon released and captured within Maines borders,” DEP Commissioner Melanie Loyzim said in a statement.

The department’s analysis of total GHG emission sources and sinks showed the state is 75% of the way to achieving its 2045 carbon neutrality target.

“Maine’s significant forest cover — approximately 89% — results in the state having a large capacity to store carbon, and in recent past, a high accumulation rate of forest carbon via tree growth, offsetting a high percentage of anthropogenic emissions,” the report said.

Forest biomass and soils in the state are sequestering -26.2 million metric tons of CO₂ (MMTCO₂) per year, while wetlands and urban biomass are sequestering carbon at -0.2 and -0.4 MMTCO₂ per year, respectively.

Although the department said there are “many uncertainties” associated with the CO₂ accounting methodologies used for the budget, it expects to continue to improve the budget, update data through 2021 for the next report and further research opportunities.

Sector Insights

While Maine’s industrial sector emissions were higher than transportation emissions from 1990 to 2009, they have steadily decreased, leaving transportation as the highest emitting sector. In 2019, the report said, the transportation sector produced 49% of all CO₂ emissions from fossil fuel combustion in the state, up from 42% in 1990. The sector also was responsible for 31% of Maine’s gross GHG emissions.

By comparison, the state’s electric power sector generated 9% of Maine’s gross GHG emissions in 2019, down 41% from 1990 levels.

For 2019, the report said, natural gas was the top contributor, at 72%, to fossil fuel-based CO₂ emissions in the electric power sector. And renewable resources, including hydropower, wood, wind, waste, solar and geothermal, provided 84% of the energy consumed by electricity generating facilities in 2019, up from 37% in 1990.

Maine’s industrial sector is the biggest contributor to emissions from the combustion of wood, and it was followed by the electric sector until the residential sector surpassed it in 2019, according to the report. In 2019, electric sector wood emissions were 13% lower than in 1990, while residential wood emissions increased 50% for the same period.