Search
`
September 6, 2024

Posted on

Killingly Stays Alive After DC Circuit Halts FERC’s Termination Order

The Killingly Energy Center saga is not over yet.

The D.C. Circuit Court of Appeals issued a stay Friday on FERC’s order to terminate Killingly’s capacity supply obligation, allowing the proposed Connecticut natural gas plant to participate in ISO-NE’s capacity auction Monday.

The stay came just 72 hours before Forward Capacity Auction 16 for delivery year 2025/26. (See Experts Expect Stable or Decreased Prices in ISO-NE Capacity Auction.)

“Absent other legal developments, the ISO will comply with this order in the conduct of the auction and will therefore unwind the actions it had taken to terminate Killingly,” ISO-NE said in a notice to stakeholders Friday evening. “After FCA 16 is conducted, should FERC confirm the termination of Killingly, the ISO would adjust the auction results to reflect the removal of Killingly.”

ISO-NE had requested the termination of Killingly’s CSO in November, saying that the project would not be able to meet key milestones for fulfilling its capacity obligations.

FERC approved the termination Jan. 3, writing that it was “persuaded by the evidence” presented by ISO-NE (ER22-355). That meant Killingly would have to forfeit its CSO for 2022/23 and would not be able to take part in FCA 16. (See FERC Accepts ISO-NE Request to Terminate Killingly CSO.)

The D.C. Circuit ruled that the order cannot be enforced until FERC “resolves” developer NTE Energy’s Jan. 11 petition for rehearing.

The rehearing request would be automatically denied “by operation of law” if the commission does not act on it within 30 days.

The court’s full opinion was not yet available as of Saturday. Judge Robert Wilkins noted in the order that he would have denied the stay, but Judges Neomi Rao and Ketanji Brown Jackson sided with NTE.

The developer did not immediately respond to a request for comment.

In a second notice Sunday, the RTO said it had declined suggestions that it delay the auction. Instead, ISO-NE said it will calculate prices and quantities cleared with and without Killingly. “The ISO intends to keep these results confidential until there is greater certainty about Killingly’s status. This will protect the commercially sensitive information that might otherwise be revealed as part of the auction finalization process,” said Allison DiGrande, director of Participant Relations & Services. “This approach will allow the ISO to conduct the auction in a timely fashion, consistent with the requirements of its tariff, while addressing the uncertainty created by the recent D.C. Circuit Court of Appeals order.”

DiGrande said the RTO also will not reveal the results of any clearing in the substitution auction until Killingly’s status is resolved. “The ISO believes that this is the most prudent path to both minimize disruptions to the administration of FCA 16 and the required timing of [Forward Capacity Market] activities related to subsequent auctions. After due consideration, the ISO is confident that this approach will ensure the integrity of the auction while also complying with the D.C. Circuit Court of Appeals order.”

In a subsequent notice on Feb. 11, the RTO announced that NTE had been suspended from the markets and told stakeholders that “a
market participant would not be allowed to participate in an Forward Capacity Auction (FCA) unless it was in compliance with the Financial Assurance Policy.”

Five business days after being suspended, a company’s CSO would be terminated and financial assurance forfeited.

Posted on

Oregon IOUs Seek to Nix Wildfire Plan ‘Joint Inspections’

Oregon’s investor-owned utilities are asking state regulators to alter key provisions in a newly proposed set of rules designed to bolster utility wildfire mitigation plans.

Portland General Electric (PGE), PacifiCorp and Idaho Power on Wednesday jointly filed a draft of the proposed rules that eliminates a requirement that the IOUs collaborate with other users of shared utility poles, such as telecommunications and cable providers, on 10-year inspections to ensure compliance with wildfire safety standards.

Under current regulations, electric utilities are solely responsible for regular inspection of poles supporting their lines, the costs for which are recovered from ratepayers. In crafting the new rules requiring joint inspections, Oregon Public Utility Commission (OPUC) staff were looking to spread the cost of those inspections to other beneficiaries.

The joint inspection provision emerged as a major sticking point at a Jan. 18 OPUC meeting, when the commission voted to proceed with a formal rulemaking process for the broader ruleset that includes the provision despite utility objections. The commissioners urged commission staff and the IOUs to negotiate a revision for the commission to consider before the rulemaking begins. (See Ore. PUC Advances Wildfire Rulemaking Despite Utility Concerns.)

The IOUs voiced concern about the complexity — and risk — of relying on joint inspections, especially for utility poles in high fire-risk areas that might have multiple users and owners.

“We have significant concerns that the proposed joint inspection mandate will cause delays to find and remediate issues found in high fire-risk zones and inevitably increase wildfire risk,” Larry Bekkedahl, PGE senior vice president of advanced energy delivery, said at the Jan. 18 meeting.

Bekkedahl said PGE preferred to continue the existing policy of solo inspections, a position backed by representatives from PacifiCorp and Idaho Power. Commissioner Mark Thompson sympathized with the IOUs, even suggesting he was disinclined to vote in favor of the rulemaking over doubts that the commission could resolve the joint inspection issue during the formal process.

The IOUs offered a blunt solution to the problem in their redline draft, striking the definition of “joint inspection” and any additional references out of the proposed rules — an approach likely to get pushback from commission staff.

More Redlines

The redline draft also addresses the IOUs’ concerns regarding another section of the proposed rules that could put utilities in conflict with municipal codes when trimming trees away from lines in high fire-risk zones within urban areas. The IOUs’ revisions would clarify that utilities are exempt from local ordinances around tree trimming and removal in such zones, giving primacy to OPUC standards.

Last month, the utilities suggested that the commission modify those provisions to focus utility trimming operations on only the highest risk areas, typically located outside urban areas, thereby avoiding conflicts. They appeared to change tack in response to Commissioner Letha Tawney’s questions about whether municipal codes sufficiently accounted for wildfire risk, raising concerns that ignitions in populated areas could create “real havoc.”

The IOUs suggested additional revisions, giving them more latitude in responding to safety violations discovered on non-utility-owned — or “foreign-owned” — poles, including the right to issues a pole owner a notice that specifies a timeline for repair.

“If the pole owner or equipment owner does not replace the reject pole or repair the equipment within the timeframe set forth in the notice, then the operator of electric facilities may repair the equipment or replace the pole and seek reimbursement of all costs and expenses related to correction or replacement of the reject pole or equipment including, but not limited to, administrative and labor costs related to the inspection, permitting and replacement of the reject pole,” the IOUs wrote.

A utility would also be authorized to charge the pole owner a replacement fee amounting to 25% of the cost of the work.

OPUC will meet again on Feb. 8 to discuss the wildfire mitigation plan rules.

Posted on

CARB Promises Closer Look at Biomethane Role in LCFS

Prompted by a petition from environmental justice groups, California regulators will take a closer look at the role of dairy-manure biomethane in the state’s low-carbon fuel standard this year.

The petition, submitted in October to the California Air Resources Board, asked CARB to launch a rulemaking to exclude biomethane derived from dairy or swine manure from the agency’s low-carbon fuel standard (LCFS).

The groups contend that the LCFS overstates the climate benefits of using the so-called “factory farm gas” as a transportation fuel. They say the LCFS credit system provides incentives for farm expansion, leading to increased air and water pollution. (See Petition Would Bar ‘Factory Farm Gas’ from CARB LCFS Credits.)

The petitioners include Public Justice, Food and Water Watch, the Animal Legal Defense Fund, the Association of Irritated Residents, Leadership Counsel for Justice and Accountability, and the Vermont Law School Environmental Justice Clinic.

In a response dated Jan. 26, CARB Executive Officer Richard Corey denied the groups’ request to amend LCFS at this time, calling the requests for near-term rulemaking “premature.” Corey noted that CARB will revisit the LCFS in 2023, after completing an update to its climate change scoping plan this year.

But during a CARB board meeting on Jan. 27, Chair Liane Randolph asked CARB staff to hold a public workshop in the next few months specifically on the role of dairy-manure biomethane in the LCFS, to be followed by a report to the board.

Randolph’s request came after several other board members weighed in on the issue.

Board member Tania Pacheco-Werner asked if CARB could conduct a technical review of information on dairy-manure biomethane that has come to light since the LCFS regulation took effect. She said the answers are important as several dairy-digester projects are in the development pipeline.

“Personally, I want to see resolution of this as quickly as possible,” said Pacheco-Werner, who is a governing board member for the San Joaquin Valley Air Pollution Control District.

Carbon-intensity Benchmarks

CARB’s low-carbon fuel standard assigns a carbon intensity score to different transportation fuels. It also sets a carbon-intensity benchmark that fuel providers must meet. Providers that don’t meet the benchmark can make up the difference by buying credits awarded to producers of low-carbon intensity fuels.

Dairy-manure biomethane is a fuel potentially eligible for credits under the LCFS.

The environmental justice groups’ petition alleges that the LCFS credit system doesn’t account for emissions throughout the full life cycle of the biomethane, which is generated from the anaerobic digestion of dairy cows and swine manure.

The petition says the credit system incentivizes expansion of the factory farms, which allegedly has disproportionate environmental and health impacts on low-income communities and communities of color, particularly in the San Joaquin Valley.

The petition asks CARB for a rulemaking to amend the LCFS to exclude all fuels derived from factory farm gas, or to modify LCFS to account for emissions over the entire lifecycle of dairy-manure biomethane.

In his response to the groups’ petition, Corey said CARB’s long-range scoping plan, which takes a big-picture look at greenhouse gas-reduction strategies, may include recommendations regarding the LCFS. CARB expects to finalize the scoping plan update by the end of the year.

Corey said information gathering is another key step before the agency makes changes to the LCFS. He said during the CARB board meeting that some of the issues raised regarding the LCFS are not new, and “I have not seen the evidence of the claims that are being made.”

“If there truly is new data that is contrary to the historical record and the underlying analysis, I’m very interested in seeing that,” Corey said.

Corey and other CARB senior managers met with petitioners before issuing a response, and he said further dialogue is welcome.

Methane-reduction Goal

The debate over dairy-manure biomethane came up during public comments in response to a CARB presentation on 2022 priorities.

Michael Boccadoro, executive director of Dairy Cares, a dairy industry coalition, said the digesters are essential to helping the dairy sector meet California’s goal of reducing methane emissions by 40%.

“Without digesters, there is no way to achieve the 40% goal,” Boccadoro said during the CARB board meeting. “Without markets like the LCFS for utilization of the methane that is captured, these projects are not economic and cannot be financed and implemented.”

Boccadoro previously described dairy digesters as the state’s most cost-effective and successful climate investment.

Other speakers expressed disappointment with Corey’s response to the petition.

“This petition has been brushed aside with empty promises [that] it will be considered in the future,” said Tom Frantz with the Association of Irritated Residents. “In other words, ‘Blah, blah, blah.’”

Posted on

ISO-NE’s Plan to Delay MOPR Removal Wins out at NEPOOL

NEPOOL’s senior stakeholder committee Thursday signed off on a plan to delay the elimination of ISO-NE’s minimum offer price rule (MOPR), which the RTO abruptly threw its support behind last week after months of working on a different proposal that would have removed the contentious rule immediately.

The debate over the plan initially put forward by generators Calpine and Dynegy, which ISO-NE can now submit to FERC, is the latest volley in a long-running dispute over the effects of a rapid transition to renewables on the reliability of the region’s grid.

The MOPR sets a price floor for bids into the capacity market, designed to prevent what its backers say are “artificially” low prices caused by the participation of state-supported resources.

ISO-NE said that its backing of the two-year transition away from the MOPR, rather than immediate removal, is designed to slow the entry of state-sponsored resources into the capacity market to a “steady pace” rather than a “sudden, voluminous and permanent shift.” (See In Late Twist, ISO-NE Calls for 2-Year Delay on MOPR Elimination.)

The grid operator has worried that reliability of New England’s grid could suffer from a rapid influx of sponsored resources and an exodus of existing generators.

“What I know, based on what we’ve observed and studied and seen, is that a transition offers the most measured way forward … and gives us much-needed time to put in place critical reforms,” ISO-NE COO Vamsi Chadalavada told stakeholders at the Participants Committee meeting Thursday. “We are convinced of this position and this judgment, and we do need your support, because the best way for us to move forward is collectively, rather than arguing back and forth about what’s right and what’s wrong.”

The transition plan was backed by generation, transmission and supplier sectors in the NEPOOL vote Thursday. It’s also not opposed by five of the six New England states (with New Hampshire as the outlier because the state opposes MOPR removal altogether).

But renewable developers, advocates and environmental groups have cried foul, arguing that the RTO has not made its case convincingly that the transition is necessary for reliability.

“The ISO provided no quantitative support … that deviating from its blueprint established nine months earlier to impose a delay will reduce reliability risks,” the nonprofit RENEW Northeast wrote in a memo this week, also noting that “temporary programs have a habit of being extended.”

“The grid operator’s saying we’re not going to allow new clean energy resources to fairly compete in the region’s market until almost the end of the decade,” Bruce Ho, senior advocate at the Natural Resources Defense Council, said in an interview. “That’s pretty extreme and really doesn’t seem in line with what [FERC] has been pushing for.”

Joe Curtatone, president of the Northeast Clean Energy Council, took to Twitter to slam the MOPR transition proposal.

“Much of what shapes our energy supply and the fate of our climate takes place in meetings few people know about, like at NEPOOL today,” the former Somerville, Mass., mayor wrote. “There’s a rule that forces clean energy to submit higher bids that protect fossil fuel suppliers. It’s grimy insider baseball, and it needs to stop.”

The transition plan does allow for up to 700 MW of capacity from state-subsidized resources to enter the market through a renewable technology resources (RTR) exemption in Forward Capacity Auctions 17 and 18 (300 MW in FCA 17 and 400 MW in FCA 18). And the committee approved an amendment from RENEW Northeast that would carry over any unused megawatts between those two years.

The plan now faces an uncertain future at FERC.

Members of the commission’s Democratic majority, Chairman Richard Glick and Commissioner Allison Clements, wrote recently that the MOPR makes ISO-NE’s tariff unjust and unreasonable, and that the RTO should move forward “expeditiously” with eliminating it. (See FERC Weighs in as ISO-NE Prepares for Capacity Auction.)

A FERC spokesperson said that Glick “does not want to risk prejudging the matter” and will wait for an official filing before the commission to comment on the ISO-NE proposal.

“What ISO-NE is proposing doesn’t seem to align with what commissioners are asking the grid operator to do,” Ho said. “I think we saw very clearly from the chairman … that he expects ISO New England to get rid of the unjust and unreasonable MOPR rule.”

Consent Agenda

The Participants Committee also approved three items on its consent agenda:

  • changes to the resource retirement process to allow retirement bids to be updated later in order to give generators more flexibility, proposed by Calpine and recommended by the Markets Committee last month. (See NEPOOL Markets Committee Briefs: Jan. 12, 2022.)
  • biennial review revisions to ISO-NE Operating Procedure No. 5 (Resource Maintenance and Outage Scheduling) Appendices A (Operable Capacity Calculations) and B (Outage Request Form), as recommended by the Reliability Committee.
  • revisions to Appendix G (Designated Blackstart Resource Commitment) to OP-11 (Blackstart Resource Administration), as recommended by the RC.
Posted on

New Jersey Committee Advances $45M Electric Bus Bill

The New Jersey Senate Transportation Committee approved a bill Thursday that would allocate $45 million for a three-year pilot program for electric school buses.

The bill (S759), which advanced with a 6-0 vote and one abstention, would create a program under which six districts or contractors each year would assess the reliability and effectiveness of using electric buses in place of diesel-powered vehicles. At least half of the districts or contractors would be in low-income, urban or environmental justice communities.

During the pilot, the performance of the buses would be evaluated and data on costs, maintenance, fuel and bus speed and movements would be collected and submitted to the New Jersey Department of Environmental Protection.

The bill’s introduction comes amid concerns from environmental groups that the state should move more quickly toward electrification of school and transit buses. As of last October, there were no electric school buses registered in New Jersey, said Atlas Public Policy, a Washington D.C.-based consultant on transportation and building electrification issues.  (See NJ Floats New Electric Bus Plan.)

Three environmental groups spoke in support of the bill, and nobody opposed it.

“Senate Bill 759 will begin the process of replacing diesel school buses,” Anjuli Ramos, New Jersey director at Sierra Club, told the committee. While up-front costs of electric buses are high, she said, clean energy buses can be cheaper in the long run.

“The economic and environmental benefits of using electric school buses far outweigh using diesel buses,” Ramos said.

Project Delay

Converting to electric buses is one piece of the New Jersey effort to get 330,000 electric vehicles on the road by 2025 and reach 100% clean energy by 2050. The state is mid-way through enacting a rule proposal to encourage the creation of charging stations that would service electric buses and medium- and heavy-duty trucks. (See NJ’s EV Charger Rules Face Scrutiny.)

New Jersey has allocated $22 million since 2019 for 18 school districts or bus contractors to help buy 71 electric school buses. Pam Frank, CEO of ChargEVC-NJ, an advocacy group that champions electric vehicle policies, told a senate committee in November that none of the buses are in operation.

The $45 million pilot program bill follows similar legislation introduced in November that secured Senate approval, 35-3, but did not advance in the assembly before the legislative term ended in January. That bill followed legislation that would have allocated $10 million to fund three test projects, which also did not pass.

Doug O’Malley, state director of Environment New Jersey, said he hoped the bill “can move forward quickly in both houses.”

“This pilot program is designed not only to get electric school buses on the road, but be able to figure out what works,” he said.

NJ Transit, the state’s mass transportation agency, said this week that the delivery of eight buses for the pilot in Camden has been delayed by more than six months.

The agency approved a $9.5 million purchase of eight buses in October as part of an effort to convert its fleet of 3,000 buses to zero emission by 2040. The buses will operate out of the Newton Avenue Bus Garage in Camden, which is undergoing a $3 million renovation, including the installation of chargers.

NJ Transit said this week that the agency expected the first of the new buses to arrive by the end of 2021. But they are now scheduled for arrival in June, with the full complement of eight arriving by the end of the year. The agency agreed to the delay during the solicitation phase, at the request of vendors who sought more time to prepare, a spokesperson told NetZero Insider.

Posted on

Report Warns of Growing Cyber Dangers

A handful of high-profile cyberattacks grabbed headlines last year, but cybersecurity advisory firm Tenable said in a report this week that the biggest challenge for the security community continues to be “age-old security challenges in new infrastructure.”

“Organizations continue to struggle with protecting, or even defining, the perimeter. Migration to cloud platforms, reliance on managed service providers, software and infrastructure as a service have all changed how organizations must think about and secure the perimeter,” the 2021 Threat Landscape Retrospective said. “Fragmented security solutions and poorly defined security outcomes must be left behind to match the complexity of the modern attack surface.”

Tenable’s goal was to highlight the security issues that plagued the public and private sector last year. While big events drew most of the public’s attention last year — for example, the compromise of the SolarWinds Orion network management software that began in December 2020, and the ransomware attack against Colonial Pipeline in May — the firm said these hacks were the tip of the iceberg, with 1,825 total breach events detected from Nov. 1, 2020 to Oct. 31, 2021.

OT, IT in ‘Attackers’ Crosshairs’

While details on many of last year’s cyber incidents have not been disclosed due to security and privacy concerns, or the desire of companies involved to avoid embarrassment, Tenable’s analysis shows more than 260 terabytes of data was stolen comprising 1.8 billion files, documents or emails.

About 38% of all breaches that Tenable analyzed were the result of ransomware attacks, such as the one against Colonial that led to the shutdown of the company’s entire pipeline network and stifled the flow of petroleum products to the U.S. East Coast. (See Colonial CEO Welcomes Federal Cyber Assistance.) Meat supplier JBS suffered a similar ransomware attack; like Colonial, its leadership decided to pay the attackers to unlock their computer systems and prevent the release of sensitive data. The two companies’ ransoms amounted to the equivalent of around $16 million.

While the Colonial and JBS breaches garnered national attention and concern at the highest levels of government, the energy, infrastructure and utilities sectors accounted for only a small fraction of ransomware attacks and total breaches. As in 2020, Tenable found that attacks fell most heavily on the healthcare sector, which accounted for nearly a quarter of the year’s total events, followed by education, with 13%.

However, the firm warned that utilities and other critical infrastructure operators should not rest easy, since last year’s incidents “proved that information technology (IT) and OT [operational technology] environments are in attackers’ crosshairs,” along with critical infrastructure. And since many of the same software tools are used across multiple industries, successfully breaking into one common platform can render all its users vulnerable.

This is what happened with the SolarWinds hack, in which the breach of the Orion software — now attributed to Russia’s Foreign Intelligence Service — may have exposed the information of thousands of customers, including the Department of Energy and FERC. (See FERC, E-ISAC Report Details Reach of SolarWinds Compromise.) The same hackers have since been blamed for additional attacks, including breaches of Microsoft and computer services provider Pulse Connect Secure.

Zero-days Across Common Software

A common point of entry for hackers are zero-day vulnerabilities, defined by Tenable as software or hardware flaws that are “unknown to a vendor prior to [their] public disclosure, or [have] been publicly disclosed prior to a patch being made available.” The firm identified 105 zero-day vulnerabilities in 2021, of which 83% are known to have been exploited in the wild. The report said that details of these weaknesses “are often kept under wraps” to prevent them from being exploited.

Two-thirds of the discovered vulnerabilities originated with just three companies: 28% in Microsoft products, 21% from Apple, and 18% from Google. Thirty percent of the vulnerabilities were detected in web browsers and 26% were in operating system software, with the rest found in web apps, email clients, office suites and other software products.

2021 zero-day vulnerabilities by vendor (Tenable) Content.jpg2021 zero-day vulnerabilities by vendor | Tenable

 

Tenable warned that while these vulnerabilities are “primarily leveraged in limited, targeted attacks” and therefore usually have limited impact at first, cybersecurity professionals cannot afford to disregard their dangers.

“The true value of a zero-day vulnerability is often not defined by its exploitation prior to discovery, but by the blog posts and proof-of-concept code published in the weeks and months after disclosure,” Tenable said. “Zero-day vulnerabilities typically become more problematic for most organizations after they’ve made the transition to legacy status, particularly if an organization has not yet applied available patches before widespread exploitation begins.”

Posted on

NRC Finds Cybersecurity Deficient at Davis-Besse

The Nuclear Regulatory Commission this week ruled that the Davis-Besse nuclear plant in northwest Ohio violated cybersecurity rules and ordered it to develop new procedures.

The plant also now faces a series of stepped-up inspections to make sure its staff are following the new cybersecurity procedures.

NRC noted in a letter made public this week that Davis-Besse and its owner Energy Harbor, headquartered in Akron, agreed to a cybersecurity “performance deficiency” during a Dec. 6 closed-door meeting with the commission but disagreed about how significant the lapses were. The company has 30 days to appeal.

The commission uses a four-color code to signify the seriousness or significance of the citations it issues, which determines the subsequent level of future inspections the citations will bring.

A “green” citation indicates a minor infraction, without further significance, similar to a warning that law enforcement might issue to a speeding motorist. More serious citations are “white,” the next level, or “yellow,” leading to increasingly wider and more intrusive inspections. The fourth color is “red,” the most serious citation, typically leading to inspections of multiple systems, often plant-wide, all of it billed to the plant owner.

NRC stated the cybersecurity citation is “greater than green” but did not specify how much greater, meaning the citation is at least a “white” finding and could be “yellow” or even “red.” Cybersecurity violations are not publicly explained in detail, nor are appeals made public. Companies are by law not permitted to discuss publicly the details of cybersecurity violations. Energy Harbor did not return phone calls seeking comment.

The company is simultaneously opposing NRC findings on a maintenance issue at Davis-Besse that could affect the entire commercial nuclear industry.

Energy Harbor is fighting a preliminary citation that Davis-Besse’s failure over 15 years to inspect and clean electrical switches controlling the power output of the plant’s two emergency diesel generators (DGs) led to their failure to actually generate power when they were started during routine testing. In other words, the diesel engines fired up, but their generators did not produce power.

The preliminary finding was issued in December. (See NRC Preparing to Cite Davis-Besse Nuclear Plant on Safety Issue.)

Emergency DGs are crucial safety equipment capable of powering emergency cooling and other systems during a reactor shutdown and a simultaneous loss of power from the transmission grid. They are not often used, but when they are, they must work. That’s why nuclear plants have two, one of which is a backup.

An NRC “greater than green” citation that the electrical switches controlling the output of the generators require scheduled maintenance could have industry-wide significance because every nuclear plant is equipped with emergency DGs.

During a two-hour teleconference with NRC this week, the company’s engineers argued the that the failure of the electrical contacts in the switches was inherent in the materials used to make them and not because of lack of maintenance.

The commission is not expected to make a final ruling on the switches until March.

Posted on

California PUC Weighs Changes to Contentious Solar Plan

The California Public Utilities Commission said Thursday it will delay indefinitely a vote on its controversial plan to reduce net metering payments to rooftop solar owners as it considers rewriting the proposal.

The proceeding, led by former Commissioner Martha Guzman Aceves, is now in the hands of new President Alice Reynolds, who previously served as energy adviser to Gov. Gavin Newsom.

“The assigned commissioner [Reynolds] has requested additional time to analyze the record and consider revisions to the proposed decision based on party comments,” Administrative Law Judge Kelly Hymes wrote in an email to parties in the proceeding.

“The proposed decision, which was issued on December 13, 2021, will not appear on the commission’s voting meeting agenda until further notice,” Hymes said.

In an email to clients, ClearView Energy Partners said, “We regard [this] as perhaps the strongest indicator from the CPUC to date that significant changes to the proposed decision are likely. On this point, we reiterate our long-held view that the final decision may move more toward the recommendations from solar advocates.”

The “provision most susceptible to change” is a proposed $8/kW grid participation charge that has particularly irked homeowners, ClearView said.

California Sen. Diane Feinstein wrote to Reynolds on Jan. 25, recommending that the CPUC reconsider the grid participation charge “to spur adoption of this technology.”

“The fee structure should properly reflect the benefits of distributed generation and promote wide adoption of rooftop solar,” Feinstein said.

Newsom, too, has said he thinks the plan needs work. (See CPUC Takes Heat on Rooftop Solar Plan.)

Opponents of the plan spoke in public comments at the CPUC’s Jan. 27 voting meeting for more than eight hours, leaving only a short time at the end of the day for the commission to take up its scheduled business. (The net metering proposal was expected to be taken up at the meeting, the earliest date on which it could be heard, but the CPUC did not put it on the agenda.)

The proposed decision, released in December, would reduce electric bill credits for homeowners with rooftop solar arrays by up to 80% and add the monthly grid charge to their bills. (See California PUC Proposes New Net Metering Plan.)

In the decision, crafted by Guzman Aceves and Hymes, the CPUC said the current net metering scheme unfairly shifts costs from homeowners who can afford rooftop solar to those who cannot.

It “negatively impacts nonparticipating customers, is not cost-effective and disproportionately harms low-income ratepayers,” Hymes wrote.

Estimates of the annual cost shift have ranged from more than $1 billion to $3.4 billion.

Opponents, led by the solar industry, have contended it will decimate rooftop solar adoption.

Homeowners who purchase rooftop solar arrays and return electricity to the grid have never paid a connection fee and are compensated at full retail rates, which are more than utility-scale solar costs. California has approximately 1.3 million rooftop solar arrays as a result of the generous incentives, advocates argue.

Those who support the CPUC’s proposed decision, including the state’s large investor-owned utilities, argue utility-scale solar is more cost-effective and can serve far more consumers that rooftop arrays.

Hymes said in her email Thursday that she would update parties on the next steps.

“After additional analysis is conducted, I will issue a subsequent ruling providing information on the proceeding schedule and details regarding the oral argument hearing,” she said.

Posted on

Coalition Forms for Consumer Choice in Retail Energy Markets

Six independent power producers and electric retailers announced Thursday they have formed a new organization to promote renewable energy and lobby states for greater customer choice.

The Retail Energy Advancement League (REAL) said it will push for more consumer control over the purchase, production and consumption of electricity, data usage and energy services.

REAL spokesperson Kate Philips said the organization believes “customer empowerment can be a lever” for aiding the transition to a low-carbon power system. Philips said REAL’s set of principles include putting control of energy decisions in the hands of consumers and a belief that “advanced competitive retail energy markets” can aid in the “modernization” of energy markets.

The founding companies of the group are IPPs Calpine Energy, NRG Energy (NYSE: NRG) and Vistra (NYSE: VST) and green retailers CleanChoice Energy and IGS Energy. Retailer Constellation Energy (NASDAQ: CEG), which separated from Exelon this week, serves as a founding associate member.

“Americans deserve easily accessible energy choices that reflect their lifestyle goals and choices,” said NRG CEO Mauricio Gutierrez, chair of REAL. “It’s time to allow competitive energy markets to drive innovation and put the power in the hands of people.”

REAL’s Board of Director’s include Gutierrez, Vistra CEO Curt Morgan, CleanChoice Energy President and CEO Tom Matzzie, IGS Energy President and CEO Scott White and Calpine Energy President and CEO Jim Wood. Its first CEO is expected to be announced at the National Association of Regulatory Utility Commissioners’ Winter Policy Summit in Washington later this month.

Maryland, Pennsylvania, Arizona

The group says it believes “competitive retail suppliers should be the entities tasked with helping customers achieve their energy goals.”

Philips said companies are motivated more today to invest in clean energy solutions, and a market that “enables regulated utilities to focus on maintaining and improving the state’s power infrastructure” can promote investment in new technologies.

REAL plans on having a “strong presence” in state capitals across the country, Philips said, and wants to work with other groups with shared goals. REAL is already teaming up with the existing Choose Who You Use electricity consumer campaigns in Maryland, Pennsylvania and Arizona.

Philips said polls consistently say customers want choice in their energy decisions. She said REAL will look to make policy decisions “based on what’s best for our customers in states across the country.”

“We think the market works better when the satisfying the consumer is the driving incentive, and not just whatever monopolies can convince regulators to let them charge their monopoly customer base,” Philips said. “Whenever they are polled, people say they want choice — and do not understand why energy is the single sector where they don’t have it. Every state that offers customer choice, but has chosen to put limits on it, has a waiting list out the door.”

Listening to Consumers

REAL officials cited a 2018 survey by Consumers Union, publisher of Consumer Reports, that gauged consumers’ attitudes toward their utility companies.

The findings included customers agreeing with the statement “I want to be able to choose my electricity provider” by a 10-to-one margin, with 76% supporting increased use of renewable energy. The survey also found that an additional 48% of all Americans would be willing to pay $5 more per month to buy 100% renewable energy.

Travis Kavulla, vice president of regulation for NRG Energy, said in a Twitter thread on Thursday that there is “a lot of work to be done” to make sure customers that already have a choice in their energy provider are “educated and empowered” in knowing their options and finding ways to improve their options.

“In every other part of our society we empower individuals to make the decisions that are best for their families and their businesses,” Kavulla said. “The electric sector stands out like a sore thumb — even at a time when we are more and more relying on it to drive a transition.”

Posted on

GSA, DOD Gear up to Meet Biden’s 100% Clean Energy Goal

The U.S. government, which buys more than 9 TWh of electricity per year from competitive retail markets, issued a request for information Thursday in its first step toward ensuring all that power will be carbon-free by 2030.

President Joe Biden set that goal in December, with his executive order on federal sustainability and energy procurement (EO 14057).  The order calls for each federal agency to “increase its percentage use of carbon pollution-free electricity, so that it constitutes 100% of facility electrical energy use on an annual basis, and seek to match use on an hourly basis to achieve 50 percent 24/7 carbon pollution-free electricity, by fiscal year 2030.”  (See Biden Calls for Federal Procurement of 100% Clean Energy by 2030.)

The RFI is a joint effort by the General Services Administration and the Department of Defense and particularly seeks input from power providers and other stakeholders in the PJM, ERCOT, ISO-NE, MISO and NYISO markets. The deadline for submitting comments is March 7.

Annual targets for carbon-free electricity (CFE) procurement across these markets include:

  • A minimum of 100-250 GWh for each of the five RTOs and ISOs or
  • 500-1,000 GWh for ERCOT and PJM or
  • more than 1,000 GWh for PJM only.

In a press release announcing the RFI, Federal Chief Sustainability Officer Andrew Mayock said that leveraging that kind of “scale and procurement power” will allow the Biden administration to “accelerate the development of America’s emerging clean tech industries,” create jobs and help American businesses compete in global markets.

The RFI guidelines use a broad definition of carbon-free electricity, ranging from solar, wind and geothermal to nuclear, “renewably sourced hydrogen” and fossil fuels with carbon capture and storage “that meets EPA requirements.”

But the guidelines clearly lean toward renewables and set high standards for potential projects. For example, the government would prefer carbon-free procurements that provide “new or previously underutilized generation sources” and that are located within a grid operator’s service territory. The expectation is that these procurements could spur 10 GW of new clean energy development across the country by 2030, the RFI says.

Further, to avoid any appearance of greenwashing, the RFI also requires new renewable projects to come with bundled renewable energy credits (RECs), indicating that the government wants to ensure the RECS are retired, rather than being sold to offset a utility’s or corporation’s carbon emissions.

The government expects the CFE procurements “to be integrated into existing electricity procurements in a phased approach over several years, through both the transition of existing retail supply contracts, and where appropriate, new power generation procurements,” the RFI says.

The GSA and DOD want to start phasing in contracts for clean power this year, with deliveries beginning in 2023.

Noting that the DOD is one of the largest electricity users in the U.S., Deputy Secretary of Defense Kathleen Hicks said the RFI will signal to the market the government’s intent to play a leading role in the energy transition. “It’s not just critical to addressing the threat of climate change, but also to our national security as we work to secure U.S. competitiveness in rapidly shifting global energy markets,” Hicks said.

24/7 Clean Power

The big question now is whether and how individual RTOs and ISOs will be able to meet the government’s goals. While ambitious, figures on current renewable generation and projected growth suggest the CFE procurement targets are achievable.

PJM Generation by Fuel Source (Monitoring Analytics) Content.jpgPJM generation by fuel source | Monitoring Analytics

According to figures from FERC, renewable energy represented 85.9% of new generation in the U.S. in the first 10 months of 2021, and the National Renewable Energy Laboratory has reported that interconnection queues across the country are backed up with 750 GW of wind, solar and storage projects.

Coming up with 250 GWh may not be a big stretch for ISO-NE, which at present supplies about 500 GWh to the federal government and had almost 19,500 GWh of renewables, including hydro, in its generation mix in 2021, 19% of its generation.

Similarly, at 7,500 GWH per year, PJM is the government’s top retail market power provider and, as of 2020, was producing more than 30,000 GWh from wind and solar. PJM is planning to change its rules for connecting new wind and solar projects to the grid so that shovel-ready projects will go to the head of the queue. The proposed changes would also streamline approval for projects that do not require a facilities study or any network upgrades. (See PJM PC/TEAC Briefs: Jan. 11, 2022.)

The bigger challenge may be meeting the executive order’s requirement that 50% of the power procured be able to match demand hour for hour around the clock. For example, the RFI guidelines do not include energy storage as part of annual calculations of 100% carbon-free energy but can be included as part of a portfolio of resources to meet the 24/7 power matching requirements.