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December 29, 2024

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California Bills Seek to Expedite Transmission Projects

SACRAMENTO, Calif. — Two bills introduced in the California legislature this year are intended to speed up approval and construction of transmission projects necessary for the state to meet its goal of supplying 100% clean energy to retail customers by 2045 while maintaining grid reliability.

One measure, Senate Bill 420 by Sen. Josh Becker, would require the governor to identify a lead agency to “monitor clean energy and electrical transmission facility planning and deployment” needed to achieve the targets of Senate Bill 100, which established the 100% clean energy mandate in 2018, and last year’s SB 1020, which set interim goals of using 90% carbon-free electricity by 2035 and 95% by 2040.

A project that the agency identifies as necessary to meet the goals would qualify for streamlined government approval and faster court review of lawsuits filed against it. It could also receive expedited review by the California Public Utilities Commission if CAISO’s Board of Governors determines it is the most cost-effective solution to a “specific transmission expansion need” identified by the CPUC in its resource planning role.

Lawsuits and “duplicative review” by CAISO and the CPUC can delay transmission projects for years, Becker said in a news release.

“This isn’t about cutting corners,” the state senator said. “It’s about streamlining the process and getting power where it needs to go in a reasonable timeframe. We talk a lot about bringing new clean energy projects online, and while that is critical, it’s only one piece of the puzzle.  We need to be able to get that power from the plant to the homes and businesses that need it.”

The bill will be heard in the Senate Environmental Quality Committee on March 29.

CEC Certification

Another measure, SB 619 by Sen. Steve Padilla, would expand the California Energy Commission’s power to certify transmission projects entailing a capital investment of at least $250 million over five years.

Legislation signed by Gov. Gavin Newsom in June allowed the CEC to consolidate permitting for generation, storage and transmission lines that carry clean power to junction points with existing transmission. The CEC approval generally bypasses other federal, state and local permitting processes. (See California to Pass Sweeping Energy Policy Changes.)

Padilla’s bill would remove the requirement that power lines connect with existing transmission and allow the CEC to approve projects “regardless of whether the electricity is carried to a point of junction with any interconnected electrical transmission system,” the state Legislative Counsel’s office said in its summary of the measure.

The bill is short and vague on details. It is “intended to be the starting point for a much larger and overdue conversation within the Legislature on how to meet our climate goals, deliver reliable power to homes and businesses, manage costs, and add transparency to modernizing California’s electrical grid,” Padilla’s office said in a statement.

Padilla and Becker both cited CAISO’s inaugural 20-Year Transmission Outlook, released in February 2022, as support for their bills. To meet SB 100’s goals, the ISO projected the state needs $30.5 billion in new high-voltage lines to transport renewable power from remote areas to urban load pockets. (See CAISO Sees $30B Need for Tx Development.)

The amount includes an estimated $12 billion for 500-kV AC and HVDC lines to carry 10 GW of out-of-state wind power from the Great Plains and Rocky Mountain states; $11 billion to upgrade CAISO’s system with 230- and 500-kV lines to transport solar and geothermal power; and $8 billion for 500-kV and HVDC lines to carry 7 to 13 GW of California offshore wind to major urban areas.

“Meeting this unprecedented demand will require California to simultaneously accelerate planning, siting, permitting and construction of a modern electrical grid, while carefully managing its costs,” the statement by Padilla’s office said. “Current transmission projects are delayed by almost five years and have run up tens of millions of dollars in extra costs.

“Absent substantial changes to the state’s current planning and permitting processes, California will not meet its visionary climate goals, and the state’s fragile energy grid will experience unprecedented strain,” it said.

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PJM MRC/MC Briefs: March 22, 2023

Markets and Reliability Committee

PJM Gives Update on December Winter Storm Report

VALLEY FORGE, Pa. — Adam Keech, PJM vice president of market design, told the Markets and Reliability Committee last week that the RTO is delaying its estimation of when it will be publishing a report on the December winter storm to July.

In committee meetings following the storm, also known as Winter Storm Elliott, PJM initially stated that it was planning to release the report in April. But Keech said that staff are diverting resources to a data request related to the storm from NERC and FERC, followed by a visit from the two organizations in April. Staff are also working to address a list of compliance filings FERC required in its conditional approval of PJM’s proposal to allow aggregated distributed energy resources to participate in its markets.

The report will likely be structured similarly to the paper PJM released following the 2014 polar vortex, with chapters on generation performance and gas availability, load forecasting, timing and criteria for emergency procedures, Capacity Performance, dispatch, and the cost offer verification process.

In the meantime, Keech said PJM plans to provide lessons learned from the storm during stakeholder meetings in mid-May, focusing on the capacity market to inform changes being considered through the Critical Issues Fast Path (CIFP) process. He said many of the major items that will likely be presented have already been under stakeholder discussion even before the December storm. (See PJM Board Initiates Fast-track Process to Address Reliability.)

“We’ve been working on many of the issues you will see already for the past year,” he said.

Stakeholders Support New Default CONE and ACR Values

Both the MRC and Members Committee supported the proposed default cost of new entry (CONE) and avoidable-cost rate (ACR) through advisory votes. The changes are now set to be filed with FERC, with the goal of being in place for the 2026/27 delivery year. PJM elected for a same-day vote for the MRC and MC to give the Board of Managers more time to review the information before the filing. (See “Updated Default CONE and ACR Figures,” PJM MRC/MC Briefs: Feb. 23, 2023.)

The gross CONE values for all resource types, except storage, would increase, which PJM’s Skyler Marzewski said is largely because of changes to investment tax credits under the Inflation Reduction Act. The CONE changes also include new reference resources for combined cycle and onshore wind resources.

The most significant changes to ACRs include adding steam oil and gas as a new default unit type, including more data from the Nuclear Energy Institute for calculating nuclear costs and refined estimates of property taxes and insurance costs. All gross ACR values increased except single-reactor nuclear facilities.

PJM, Monitor Present Renewable Dispatch Proposal

Joel Romero Luna of Monitoring Analytics and PJM’s Darrell Frogg presented a first read of a joint proposal to create new dispatch protocols for renewable resources, with the aim of increasing visibility of what level renewables can be reduced to. Frogg said as more intermittent resources come online, it is likely that there will be more dispatch required, and those resources will not be able to provide their maximum output whenever they are available.

The proposal would use basepoints currently available through the Inter-Control Center Communications Protocol (ICCP) rather than curtailment flags, and intermittent resources would be directed to follow their economic basepoints even when they are curtailed because of the prevalence of inadvertent curtailments. Resources would be required to update critical parameters in real-time security-constrained economic dispatch (SCED) every five minutes and on an hourly basis for parameters in intermediate-term SCED cases.

The current lost opportunity cost (LOC) structure for wind resources would be extended to solar generators, making them eligible for LOC when they follow SCED dispatch and have the ability to receive instructions from PJM.

Frogg said the proposal is an effort to require intermittents to offer their median or expected output into the day-ahead market, based on forecasts of both weather and equipment availability.

Responding to stakeholder questions, Luna clarified that there is currently a requirement that units must offer into the market, and while most intermittents already follow the practice being proposed, there is insufficient clarity in the manuals codifying the process.

Economist Roy Shanker questioned how generators’ forecasts will be reviewed for accuracy by PJM, saying that outside forecasts should be checked for accuracy to avoid a bias being developed.

Monitor Joe Bowring said they believe the right amount of review is already included in the proposal and no further changes are needed.

Members Committee

Deficiency Notice Interrupts Timeline on CP Penalty Payments

Just the day before the committee meetings, FERC issued a deficiency notice on PJM’s filing to allow market participants that have defaulted to continue operating in its markets under certain conditions, including their contribution to reliability, the ability to generate revenues in the future and capability to post collateral (ER23-1058).

A fourth factor recognizes that certain transmission customers cannot have their service terminated without FERC approval. (See “1st Read on Proposal to Allow Flexibility for Market Participation During Defaults,” PJM MRC Briefs: Nov. 16, 2022)

The notice “is of concern for those following Winter Storm Elliott, because we are getting ready in April to send out the invoices for the Capacity Performance penalties,” PJM General Counsel Chris O’Hara told the MC.

In its response to the notice, filed Thursday, the RTO said it had accidentally included the last four words in the phrase, “PJM may permit a defaulting market participant to continue to participate in PJM markets in a limited manner,” in the proposed revisions to the Operating Agreement; they had been in an early draft but deemed too vague — as FERC noticed — and were meant to be removed.

PJM also stated that the four factors it identified consisted of an exhaustive list of the circumstances under which it would allow market participants to continue operating while in default.

The RTO asked FERC to implement a shortened five-day comment period and to rule on the proposal by April 7, with an effective date of April 8.

“PJM requested these dates purposefully,” the RTO said in its response. “PJM is required to issue the March monthly bill by April 7, 2023. Those monthly bills will include any nonperformance charges related to Winter Storm Elliott. The aggregate nonperformance charge will be between $1 [billion] to $2 billion. While PJM has proactively acted to reduce the risk of capacity market seller default by proposing to amend the manner in which the Winter Storm Elliott nonperformance charges may be billed, the risk of default will remain, even if those revisions are accepted,” referring to a separate filing that would allow market participants to opt to make their payments over a longer period.

O’Hara said PJM is concerned about the possibility of defaults stemming from the nonperformance charges, not just in terms of the absolute number of megawatts affected, but also the potential for generators providing critical services such as black start or critical load units being at risk. Should owners of those facilities be considering default, he said PJM wants a conversation to be opened so that they can seek a waiver request at FERC to allow them to continue operating.

Stakeholders Question CIFP Process

Steven Lieberman of American Municipal Power said he believes the PJM board has not met the requirements for initiating the CIFP process that it began in February, arguing that it has not set a firm deadline for resolving the issue.

While the board has identified Oct. 1 as the date for PJM to make a filing to address reliability concerns identified in about five years, Lieberman argued that the deadline is arbitrary. (See PJM, Stakeholders Present Initial Capacity Market Proposals to RASTF)

“It’s our opinion at least that it doesn’t satisfy the requirements for starting the CIFP process in the first place. … We think this process was elected in a way that conflicts with Manual 34,” he said.

Lieberman also said the board’s letter opening the CIFP is vague and does not lay out a process that fosters the kind of open and transparent dialogue that the letter states the board hopes to have with stakeholders as they create proposals. He noted that stakeholders had requested that the board attend future MRC or MC meetings to speak about the scope it envisioned for CIFP proposals and what its largest concerns are, but that PJM determined it would not be proper to have individual members potentially speaking on behalf of the entire board.

Greg Poulos, of the Consumer Advocates of the PJM States (CAPS), said generator performance is the key issue for many state advocates, but he believes it will be hard to create a proposal addressing the issue when the data on performance during Elliott won’t be available until July.

“When you look at what our dates are and what we’re trying to achieve, it is hard to match it up,” he said.

Susan Bruce, representing the PJM Industrial Customer Coalition, agreed that the deadlines are optimistic, and attempting to address too many portions of the capacity market on a short time frame may prove difficult. She said stakeholders should have a disciplined mindset rather than allow the process to become “an invitation for a Christmas tree.”

Erik Heinle, Vistra’s director of PJM market policy, said he believes the board letter was well written and provides enough clarity on the areas it believes that proposals must address, while also leaving stakeholders discretion to include other topics as well. He noted that any issues not addressed by the CIFP could be open for continued discussion through the Resource Adequacy Senior Task Force, which is currently on hiatus through the CIFP deliberations.

Other Stakeholder Discussions

MC Chair David “Scarp” Scarpignato said stakeholders are considering whether to start MC meetings earlier on days when the MRC adjourns significantly earlier than scheduled. He said that in some cases, stakeholders must wait for hours before the MC starts. Those with comments or suggestions were encouraged to reach out to Scarp or PJM Director of Stakeholder Affairs David Anders.

The MRC tabled a vote on proposed revisions to Manual 11: Energy & Ancillary Services Market Operations because of amendments offered in an attempt to better align the manual with PJM’s other governing documents. Monitor Bowring and some stakeholders suggested that the proposed changes to the revisions may be substantive at first glance and it would be better to wait a month to review before taking a vote.

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New York Considering Standards for IBRs

[EDITOR’S NOTE: A previous version of this article made it unclear that PRR-151 has not been fully approved by the NYSRC; the council approved publishing the proposed rule for comment.]

The New York State Reliability Council (NYSRC) has proposed establishing a uniform set of requirements for inverter-based resources (IBRs) over 20 MW to connect to the NYISO grid, leaving the ISO concerned that its generator interconnection queues could become even more clogged.

PRR-151, published March 10, is based on IEEE Standard 2800-2022, itself approved by the Institute of Electrical and Electronics Engineers’ board of directors in February 2022. It would direct NYISO to adapt the IEEE standard’s specifications for IBR performance criteria, databases and model validation methods — among other requirements — for use in its territory.

IBRs in the state would be required to be able to provide dynamic active support services during abnormal voltage or frequency situations, operate in active or reactive power control scenarios, and quickly communicate with NYISO during disturbances. Resource owners would be required submit self-certified compliance verifications to the ISO.

In its posting of the rule, the NYSRC cited the expected increase in the state’s renewable resources and the disturbances in California and Texas during which “IBRs failed to perform reliably, creating system supply deficits.” (See NERC, WECC Warn of Inverter Modeling Gaps and NERC Repeats IBR Warnings After Second Odessa Event.)

It also cited FERC’s Notice of Proposed Rulemaking to direct NERC to develop standards for IBRs (RM22-12). The commission noted IEEE 2800, along with several other related efforts, as “voluntary industry standards.”

“These efforts may enhance the operating performance and control capabilities of IBRs; however, these efforts remain at relatively early stages, do not apply to all relevant IBRs, and require adoption by state or other regulatory authorities,” FERC said. “The proposed directives to NERC to develop new or modify existing reliability standards are intended to complement existing voluntary efforts underway and are not intended to supersede or interfere with these efforts.” (See FERC Addresses IBRs in Multiple Orders.)

Comments on PRR-151 are due April 27.

NYISO, Stakeholders Tepid

The ISO presented the proposed rules to hesitant members of the Transmission Planning Advisory Subcommittee and Electric System Planning Working Group on Friday.

Roger Clayton, chair of the NYSRC’s Reliability Rules Subcommittee, told the groups that PRR-151 was developed because of “the poor reliability performance of like-devices in Texas and California,” and “the cumulative amount of IBRs in NYISO’s interconnection queue … warrants the implementation of IEEE 2800 to govern the interconnection of these devices.”

According to the council’s posting, as of Jan. 5, more than 50,000 MW of IBRs were in NYISO’s queue.

Clayton said the requirements are “for new generators, and the intent is for PRR-151 to not be looking backwards,” noting that they would likely be effective after the current NYISO Class Year.

NYISO had told the council it was concerned that PRR-151 would increase the amount of time required for IBRs to complete interconnection studies; could require lengthy manual and tariff revisions; and did not specify a clear timeline for generator owners to begin demonstrating compliance. Many of these sentiments were shared by stakeholders at the meeting.

Doreen Saia, an attorney with Greenberg Traurig, said developers need to understand how the rules would affect them “because otherwise all we’re going to have an unholy mess on our hands.”

In response to the unease, Chris Wentlent, chair of the NYSRC’s Executive Committee, said PRR-151 “is a draft rule” and that the council’s goal “was to get [PRR-151] to the surface so everyone is paying attention to it,” as well as “allow folks to start commenting.”

Wentlent later promised to consider giving stakeholders an in-depth technical presentation on the proposed rules.

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TVA Signs Multinational Nuclear Investment Pact on SMR Technology

The Tennessee Valley Authority last week struck a multinational agreement on small modular reactor development with GE Hitachi Nuclear Energy, Ontario Power Generation and Synthos Green Energy, a Poland-based wind and nuclear generation developer.

Under the partnership, the companies will develop and invest in a standard design for the GE-Hitachi BWRX-300 small modular reactor (SMR) that they hope will be licensed and deployed in the U.S., Canada, Poland and other countries. GE Hitachi expects the companies to invest $400 million in the SMR’s development.

“It’s a great collaboration that spans three countries. … This is just the beginning, the foundation,” GE Hitachi Nuclear Energy CEO Jay Wileman said during a March 23 press conference in D.C. “This is really the launch of a platform going forward to help solve climate change.”

Wileman said nuclear energy will inevitably become part of the equation to reach net-zero carbon emissions by midcentury.

“Nuclear has to have a seat at the table, but we’ve got to earn that seat at the table,” he said. “To do that, we’ve got to be on-schedule, on-budget, and it’s got to be a competitive cost.”

He said the BWRX-300 SMR’s common design will allow it to be replicated at varied sites.

“I hope in 10, 20 years from now, people look back on this day and it will have aged well,” TVA CEO Jeff Lyash said. “What you should see here is partnership between a great technology company and three great industrial companies in the power sector.”

Lyash said energy security and decarbonization are challenges that the U.S., Canada, Poland and every other country in the world must face. “You cannot sacrifice one for the other,” he said.

“Nuclear is one of the critical solutions” to reach a secure, decarbonized energy future, Lyash said.

TVA GE Hitachi Agreement Panel (TVA and GE Hitachi) Content.jpgFrom left: GE Hitachi CEO Jay Wileman, Ontario Power Generation CEO Ken Hartwick, Synthos Green Energy CEO Rafal Kasprow and TVA CEO Jeff Lyash | TVA and GE Hitachi

 

TVA announced last year that it will build a BWRX-300 SMR by 2032 at the Clinch River Nuclear site near Oak Ridge, Tenn. The federal agency received a voucher from the Department of Energy’s Gateway for Accelerated Innovation in Nuclear to study future sites for advanced nuclear reactors. (See TVA Defends Rates, CO2 Reduction Plans in House Inquiry; TVA Receives Federal Assist on Future Nuclear Plans.)

Its Board of Directors in 2021 approved a nearly $200 million investment for a New Nuclear Program that will examine advanced reactor technology options for future deployment at Clinch River and other potential sites.

GE Hitachi small modular reactor render (GE Hitachi) Content.jpgArtist’s rendering of a GE Hitachi small modular reactor | GE Hitachi

TVA holds the country’s only early-site permit from the Nuclear Regulatory Commission. The federal utility has said it could seek licensing for Clinch River as early as this year.

Lyash says the utility’s goal is to demonstrate that it can build a fleet of SMRs in its footprint. TVA hopes to help design the next generation of reactors that will be ready to deploy in the 2040s, he said.

It plans to preserve and extend the operational life of its existing nuclear fleet, exemplified by last year’s replacement of the steam generators at Watts Bar Nuclear Plant Unit 2.

Ontario Power Generation also plans to install a BWRX-300 SMR as early as 2028 at its existing Darlington Nuclear Generating Station site on Lake Ontario. The project broke ground three months ago.

“We have a technology, we’ve got a project, we’ve got a plan to deliver new, clean electricity to our grid before the end of this decade,” Ontario Minister of Energy Todd Smith said, adding that the process began with more than 100 potential designs.

Synthos’ Orlen project aims to install 10 GW of capacity with dozens of small modular reactors across Poland between 2029 and 2036. The first 10 sites will use the BWRX-300 SMR technology.

Ontario Power Generation CEO Ken Hartwick said he hopes the partnership will inspire confidence to develop SMRs in other countries.

“I think this has been a long time coming,” he said. “This is what it’s going to take to succeed with a nuclear build. It’s going to be strong partnerships; it’s going to be stakeholder engagement and a lot of hard work, but we will succeed.”

Kathryn Huff, assistant secretary for the U.S. Office of Nuclear Energy, called the partnership a “model” for cutting-edge private investment efforts.

“It takes a lot of dollars to make real change happen, and the federal government can’t provide all of those dollars,” she said. “Our one dollar needs to turn into trillions of dollars on the private side, and this group of individuals is doing just that. This partnership is precisely what will result in commercial liftoff for small modular reactors, which the [Department of Energy] is really excited about as a technology.  … We love a public-private partnership, but a private-private-private-private partnership is even better.”

Huff said to meet climate goals, the world will need to double or possibly triple its current nuclear capacity by 2050. She said the partnership’s companies are proving it’s “implementation season.”

Poland’s ambassador to the U.S., Marek Magierowski, said that while he was trying to shy away from bold statements, he said he believed “nuclear is the future.”

“I believe this is something we can all agree on, you as producers of energy and us, the consumers,” he said. “If we want to breathe cleaner air, if we wish to satisfy our society’s ever-growing energy needs, if we want to survive global economic turbulence, we need to put more chips in on nuclear.”

Magierowski admitted that acronyms are not his forte and said he initially thought the BWRX-300 SMR sounded like a cute robot from “Star Wars.”

“I’m confident that Poland, the U.S. and Canada will become even closer to each other through such deals. As close as Luke Skywalker, Han Solo, R2-D2 and BWRX-300,” he said, jokingly.

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NERC: Cyber Intrusions Affected Multiple Regions in 2022

Electric utilities reported eight attempts to compromise their cyber systems to NERC last year, according to the ERO’s annual cybersecurity report.

And while none of the incidents affected reliability, the evidence of attackers’ ongoing efforts to destabilize the grid “highlights the continued need for vigilance,” NERC said.

NERC published the report last week in accordance with FERC’s Order 848 of 2018, in which the commission directed the development of a reliability standard to “augment mandatory reporting of cybersecurity incidents.” The initiative resulted in CIP-008-6 (Cybersecurity — incident reporting and response planning), which FERC approved the following year. (See FERC OKs Cyber Reporting Rule.)

The standard expanded mandatory reporting of cybersecurity incidents to a wider range of intrusion attempts, along with specifying the minimum information that must be reported. Responsible entities must send their reports to the Electricity Information Sharing and Analysis Center (E-ISAC) and the Department of Homeland Security’s Industrial Control Systems Cyber Emergency Response Team by the end of the next calendar day, or within one hour depending on the seriousness of the incident.

FERC’s order also directed NERC to submit an annual, anonymized public summary of the cyber incident reports received each year based on the reports received through the E-ISAC. NERC delivered its first annual cyber report last March after CIP-008-6 became mandatory on Jan. 1, 2021.

WECC, MRO, Texas RE Report Incidents

According to last week’s report, entities sent eight CIP-008-6 cyber incident reports to the E-ISAC in 2022, compared to two the previous year. Four of the reports were submitted by entities in WECC, and two each from the Midwest Reliability Organization and Texas Reliability Entity.

NERC withheld some incident data from the report, such as the utilities involved in the incidents or details about when and where they occurred, in order to prevent potential threat actors from gaining information on how to target critical infrastructure. However, the ERO emphasized that “none of the reported [incidents] successfully compromised a BES [bulk electric system] cyber system or affected reliable operations.”

Four of the reported attacks involved malware, a category that includes malicious code, Trojans (a type of malware disguised as legitimate code or software), and ransomware. Two of the malware incidents involved the exploitation of “known vulnerabilities to attack EACMS [electronic access control or monitoring systems] assets” — in one case a vulnerability in Apache’s Log4j product and in the other a weakness in software from information security company Fortinet.

Another malware incident saw the attacker attempt to use a Trojan to compromise an interactive remote access asset. For the last one, NERC said that it “only affected a few systems on the entity’s corporate IT [information technology] network” and that the Supervisory Control and Data Acquisition (SCADA) network did not appear to have been affected.

Two further incidents involved attacks on third parties — both in the WECC region — that provided support services for BES cyber systems. One third party provided backup SCADA monitoring services for two wind power facilities. The attack caused outages to its email and phone systems, and loss of access to SCADA. The other incident was a distributed denial of service attack against the internet service provider of a vendor that provided third-party forecasts for a balancing authority.

NERC also reported an attempt to remotely open a physical gate at a facility, which failed, and a final incident “of unknown origin” that led to loss of visibility in an entity’s EACMS and physical access control systems. The last incident is still under investigation.

Further Vigilance Needed

The ERO’s analysis indicated that last year’s cyber incidents “seem to have targeted specific systems related to cybersecurity defenses and BES monitoring.” Though none of the attacks affected reliability functions or successfully compromised BES cyber systems, two did succeed in compromising cyber assets associated with BES cyber systems — the one of unknown origin and one in which the attacker “was able to change several firewall rules and create administrator accounts on the affected devices before being detected.”

The attacks on vendors “impacted entities to various degrees,” but had no operational impacts on the grid. Likewise, the attack on an entity’s corporate IT system had no impact on cyber systems, cyber assets or operations. While another attacker did succeed in sending a signal to open the gate, the attempt was ultimately unsuccessful because the gate did not open.

Finally, NERC said the attempted exploit of the Log4j vulnerability seemed to be trying to find vulnerable targets rather than aiming at the responsible entity itself. There was no penetration of the entity’s electronic security perimeter and no apparent further traffic occurred other than the system sending the attacker an “awake” message.

Though NERC said it was “encouraged that there were no operational impacts from the reported incidents … and that entities reported these attempts to the E-ISAC,” it found more work is needed to improve vigilance against cyber threats. A new standards development effort is underway to enhance the reporting requirements in the form of Project 2022-05 (Modifications to CIP-008 reporting threshold). The ERO said this project is intended to “provide a minimum expectation for reporting attempts to compromise.”

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Kentucky Law Raises Hurdle for Fossil Fuel Generation Retirements

Newly enacted legislation in Kentucky could make it more difficult for the state Public Service Commission to approve retirements of fossil fuel generators or replace them with renewables.

Senate Bill 4 — filed with the secretary of state’s office on March 24 without the signature of Gov. Andy Beshear — prohibits the PSC from approving applications to retire fossil fuel generators unless the unit will be replaced with capacity that is dispatchable, “maintains or improves” grid reliability and maintains the utility’s “minimum reserve capacity requirement.”

Generation operators are required to provide the commission with the costs of retiring the facility and demonstrate that its closing will result in cost savings for customers. It also stipulates that retirements cannot cause the utility to incur “any net incremental costs … that could be avoided by continuing to operate” the generator. The decision to retire cannot be based on financial incentives from the federal government.

The legislation states that coal generators are retiring at an “unprecedented rate,” creating an emergency that could impact employment rates, tax revenue and utility rates, while also reducing reliability. The emergency clause allows the bill to take effect immediately.

Supporters of the bill in the General Assembly pointed to a whitepaper published by PJM in May 2022 that found government policies were among the largest reason for generators retiring. Opponents said keeping aging facilities online would limit the ability of utilities to keep rates low.

The bill was opposed by utilities and environmental groups, who said it would increase ratepayer costs and could harm reliability by keeping aging facilities on the grid rather than replacing them with newer technologies.

“Senate Bill 4 jeopardizes the best interests of our customers — including safety, reliability and affordability,” utility group Kentuckians for Affordable & Reliable Energy said in a statement.

“For nearly 90 years, the Public Service Commission has applied principles of least-cost to approve fair, just and reasonable rates and services. SB 4 is a fundamental departure from this proven method of regulation that will only increase rates higher than necessary to achieve safe, reliable service. This change risks Kentucky’s current competitive advantage to attract and retain the manufacturing industries essential to our economy. A diverse generation portfolio is extremely important to meeting customers’ needs and allows utilities to enhance reliability, reduce risks, and keep costs down.”

The group was formed by investor-owned utilities and generators in opposition to the bill, including Duke Energy (NYSE:DUK) and PPL (NYSE:PPL) affiliates Louisville Gas and Electric Company (LG&E) and Kentucky Utilities Co. (KU).

In an announcement following the bill’s passage, PPL said it does not believe the legislation will affect its business outlook nor its projection to receive a PSC answer on its generation replacement filings by Nov. 6, 2023. LG&E and KU are retiring nearly one-third of their capacity by 2028, to be replaced by two 621-MW natural gas plants, nearly 1,000 MW of solar and a 125-MW battery storage facility.

“We followed a well-defined and rigorous process to ensure delivery of safe, reliable and affordable energy for our customers. We’re confident that our plan exceeds the standards set out by this new law and is the best path forward for our customers. We look forward to continuing to engage with stakeholders in Kentucky and completing the process before the KPSC to demonstrate why that is,” said Vince Sorgi, PPL President and CEO.

Chris Whelan, spokesperson for LG&E and KU, said she does not believe the bill will impact the companies’ ability to obtain certificates of public convenience and necessity for the new generators.

“We had opposed this bill because we felt it … had an impact on rates and reliability for our customers,” she said.

Lane Boldman, executive director of the KY Conservation Committee, said the December 2022 winter storm demonstrated that fossil fuel generation is not as reliable as its proponents have argued. She said the ability to import wind power from other regions was central to limiting the storm’s impact.

“If you’re going to focus on reliability then you need to be focused on the transmission and the storage issue, and this was not part of the conversation that I saw,” she said. “It’s a shame there’s not more focus on resiliency at a broader portfolio of solutions, rather than just to maintain older less efficient power plants as the only option. There are other options.”

Much of the discussion in the Senate’s Natural Resources and Energy Committee focused on maintaining the coal economy in the state. Boldman acknowledged that mining communities have suffered from the industry’s decline.

“But slowing down the retirement of these coal plants only serves to impact ratepayers more, and that’s already been a problem in some of these regions … Locking people into these older coal plants is actually making it harder on the economy in those coal field regions because they have higher power bills now,” she said.

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Monitor Seeks Access to PJM Liaison Committee Meetings

The PJM Independent Market Monitor on Monday filed a complaint to FERC alleging that the RTO is in violation of its tariff by not permitting the Monitor to attend Liaison Committee meetings (EL23-50).

“It is inconsistent with the independence of PJM, the PJM board and the independence of the Market Monitor to exclude the Market Monitor from any stakeholder process,” the IMM argued. “PJM should be directed to permit the Market Monitor to register for and participate in meetings of the Liaison Committee.”

The next LC meeting is scheduled for April 3.

The Monitor was able to attend the committee’s meetings until 2018, when the Members Committee voted to enforce the LC’s charter and restrict participation to RTO members and the Board of Managers, also preventing state regulators and FERC staff from attending. The Monitor quoted the PJM tariff in arguing that it is allowed to participate in stakeholder meetings when it determines its participation to be “appropriate or necessary to perform its functions,” and that charter provisions in violation of the tariff cannot be enforced. (See “Liaison Committee Meeting to be Closed to Nonmembers,” PJM MRC/MC Briefs: Sept. 27, 2018.)

The West Virginia Public Service Commission has also filed a complaint against PJM over its exclusion from LC meetings, arguing that the tariff requires that ex officio, nonvoting members be allowed to observe and that preventing them from doing so is also a violation of nondiscrimination provisions in the Federal Power Act Sections 205 and 206 (EL23-45). (See W. Va. PSC Files Complaint over PJM Meeting Policy.)

After also being excluded from LC meetings in 2018 alongside the Monitor, West Virginia PSC staff attended two MC meetings in September and November 2021 to push for stakeholders to vote on a rule change to permit their attendance. A motion was made during the Nov. 17 meeting to open the LC, but stakeholders narrowly voted to indefinitely table discussion.

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Texas PUC Appeals Court’s Decision on Uri Transactions

Texas regulators last week asked the state’s Supreme Court to overturn a recent appeals court ruling that could force ERCOT to unwind market transactions during the deadly February 2021 winter storm.

Attorneys for the Public Utility Commission said in a filing Thursday that the appeals court’s ruling should be overturned because the orders it issued expired years ago and therefore cannot be voided. They defended the commission’s actions during the storm, saying it made “split-second decisions” necessary to help correct a market failure (23-0231).

The PUC urged the Supreme Court to review the decision, reverse the judgement, and either dismiss the case or rule in the commission’s favor.

The 3rd Court of Appeals on March 17 reversed two PUC orders to keep the market’s wholesale prices at the $9,000/MWh cap during the storm. The court found the commission’s actions “entirely” eliminated competition and were contrary to state law. It remanded the case for “further proceedings consistent” with its ruling. (See Texas Court Reverses PUC’s Uri Market Orders.)

The PUC said the high court should grant its petition because the orders in question expired shortly after the storm, rendering them moot.

“They no longer exist, so the Court of Appeals could neither affirm nor reverse them,” its attorneys argued.

The commission said the appeals court created “harmful precedent” by allowing a statute’s general policy statements to “trump both specific grants of authority and the statute’s overall policy objective.” The court focused solely on market competition, it said, ignoring the PUC’s responsibility to balance the law’s policy objectives.

It said the court’s reasoning calls into question any commission rule that “arguably limits competition” and that its “invented” constraints could hamstring future efforts by the PUC and ERCOT to “ensure ‘the reliability of the regional electrical network.’”

The PUC’s attorneys also argued that the appeals court’s decision has “surprised the electricity world” and introduced “mass uncertainty” into Texas’s electricity markets.

“The markets are already reacting to that uncertainty in ways that are hard to predict,” they wrote.

3 Mitigation Plans Amended

During the PUC’s open meeting last week, it also approved amended voluntary mitigation plans (VMP) for Luminant, NRG Energy (NYSE:NRG) and Calpine that add “clear” guidelines for their non-spin reserve service (NSRS) offering practices in ERCOT’s day-ahead ancillary services market (54739, 54740 and 54741).

Staff earlier this month determined that language in the mitigation plans provided the generators with an “absolute defense” against market abuse allegations related to the service’s submitted offers at prices up to the high systemwide offer cap (HCAP). They estimated non-spin capacity awarded to large suppliers for noncompetitive offers submitted between August 2021 and July 2022 to be between $285 million to $380 million.

The revisions eliminate language that allows offers and/or bids for day-ahead market energy and ancillary services at prices up to and including the HCAP.

Non-spin ancillary service market outcomes are affected by offers from all suppliers, and Luminant, NRG and Calpine are the largest suppliers. ERCOT’s conservative operations posture, instituted in the latter part of 2021, expanded the service’s procurement from an hourly range of 1,175 MW-1,838 MW to 3,654 MW-4,303 MW. That affected the amount of excess supply and increased the likelihood that the grid operator must rely on certain suppliers to meet procurement requirements.

Staff said that when a supplier is frequently pivotal to non-spin’s procurement, it does not forego profit if it submits offers higher than a competitive level. Instead, they said, the supplier would be incented to increase its offers to obtain excess rent and would effectively be able to control the price at which ERCOT must procure ancillary services.

Independent Market Monitor Director Carrie Bivens, who signed off on all three mitigation plans, said they were not effectively mitigating anticompetitive conduct in the non-spin market “given that there is currently no planned end date to ERCOT’s increased non-spin procurement.”

She said the amended mitigation plans will continue to provide the generators with “reasonable safeguards against the potential exercise of market power in the ERCOT markets that may constitute an abuse of market power.”

One of nine bills offered by the Texas Senate earlier this month addresses VMPs. SB2011 would require plans be updated at least once every two years and raises violations from $25,000/day per violation to up to $1 million/day per violation. (See Texas Senate Lays out Changes to ERCOT Market.)

Luminant’s mitigation plan dates back to 2019, NRG’s to 2012 (it was first amended in 2014), and Calpine’s to 2013.

The PUC did not assess any financial penalties.

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New Governor Seeks Shift in Nevada Energy Policy

Nevada Gov. Joe Lombardo on Monday announced an executive order outlining energy policies for his administration, including the state’s “advancement of energy independence.”

Nevada should develop a diverse energy supply portfolio, the order states, with a focus on affordability, reliability and sustainability. In addition to solar, wind, geothermal, hydropower, hydrogen and energy storage, Lombardo envisions a role for natural gas for electric generation and use in homes and businesses.

“The state’s energy policies shall ensure all consumers and businesses continue to have diverse energy options available to them in their homes and businesses, including electric and natural gas service, energy efficiency and renewable energy resources,” the executive order states.

Lombardo, a Republican who last year narrowly defeated incumbent Democratic Gov. Steve Sisolak, who championed clean energy policies, wants enough electric generation developed in the state “to mitigate the risk of energy markets not having sufficient electric energy supplies during peak usage periods.”

At the same time, Nevada should develop transmission and energy infrastructure to make the state a regional leader in exporting its solar, wind and geothermal energy — and to import resources as needed.

Lombardo said the state should keep exploring participation in an organized Western energy market “when such a market furthers Nevada’s objectives of reliability, affordability and sustainability.”

Lombardo wants to promote energy innovation through partnership with universities, industries and others in the state. Job creation and economic development are goals of the policies.

The order calls for streamlining the permitting process for energy projects. State agencies should review applications concurrently rather than tackling them sequentially. The governor will advocate for a similar approach at the federal level.

The order also calls for an overhaul of the Nevada Climate Strategy, adopted in 2020, to reflect the new energy policies.

“Governor Lombardo’s energy policy objectives provide a critical framework for the future of energy in Nevada,” Dwayne McClinton, director of the Governor’s Office of Energy, said in a statement.

Lombardo announced McClinton’s appointment last month. Before starting work as the new GOE director on Feb. 20, McClinton was senior legislative policy adviser at Southwest Gas. He also has experience in the renewable energy industry and worked on Lombardo’s transition team.

The Nevada Conservation League said Monday that the executive order’s support for natural gas was “the wrong direction for Nevada.”

Most of the state’s energy now comes from gas, and high gas prices are causing Nevadan’s utility bills to soar, the League said in calling for a focus on clean energy.

“Nevada has steadily made progress in reducing climate pollution and developing a local clean energy economy,” Christi Cabrera-Georgeson, the League’s deputy director, said in a statement. “Gov. Lombardo should lean in on these efforts and not hold Nevada back by relying on expensive out-of-state fossil fuels.”

Lombardo touched on the topic of energy independence during his state-of-the-state address in January.

“California does not have enough electric generation within its own state to meet its electricity needs — and is now relying on the broader Western electric market to import energy,” the governor said in his address.

“With California retiring its units and changing its transmission rules, we have no choice but to reduce our reliance on the market and seek energy independence for all Nevadans,” he added.

In his new executive order, Lombardo sets as a strategic goal “having our utilities secure sufficient energy supply through dedicated in-state energy resources, including both utility-owned and third-party-owned solar, that ensure reliability for Nevadans.”

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FERC Urged to Close ‘Regulatory Gap’ on Tx Costs

State regulators, environmental groups and ratepayers urged FERC last week to control growing transmission costs by increasing oversight of “local” projects, limiting the use of formula rates and other measures. Transmission owners defended their spending and said FERC’s existing oversight processes under Order 890 are sufficient.

FERC solicited the stakeholders’ comments after it held a technical conference on containing transmission costs last October (AD22-8, AD21-15). (See Transmission Owners, RTOs Defend Planning, Cost Control Practices.)

The Illinois Commerce Commission and New Jersey Board of Public Utilities filed joint comments noting that both states have aggressive policies to decarbonize their power systems that will require significant transmission expansion. But that does not mean transmission should be built with little to no scrutiny, which the regulators said has been happening with “supplemental projects” in PJM.

Supplemental projects (called “asset management” projects under Order 890) represented 55% of the cost of transmission entering service from 2017 to 2021, ICC and BPU said. Spending on supplemental projects totaled $13.7 billion in that five-year period, compared to just $7.1 billion in the 19 years between 1998 and 2016.

“The need for new and stronger transmission, weighed against transmission’s rising costs, potential novel technological alternative solutions, and an inability to access underlying data, puts stakeholders — state commissions in particular — in a difficult situation with respect to assessing the efficiency and cost-effectiveness of proposed transmission plans,” the BPU and ICC said. “The majority of regional transmission owner stakeholders lack the resources and information necessary to make such determinations.”

An independent transmission monitor, as initially suggested in FERC’s advanced Notice of Proposed Rulemaking on transmission, could determine how well planning processes are working and determine whether local projects’ needs might be addressed more efficiently through a regionally planned project, the states said.

“We believe a regulatory gap exists,” the Ohio Public Utility Commission’s Federal Energy Advocate told FERC. “Too many transmission projects are not receiving sufficient regulatory scrutiny to ensure regulators and the public that, at least with regard to local (i.e., supplemental) projects, the regional transmission systems are being built in a cost-effective manner.”

States are hampered in overseeing such projects in PJM because even though they are limited to a specific zone, such zones often cross state lines — as do three of the four that make up Ohio. Even if the PUC stepped up its oversight, Ohio ratepayers would still be faced with costs allocated from projects that fall outside its jurisdiction, the advocate said.

The American Public Power Association also called for FERC to address locally planned projects.

“Among other potential problems, the magnitude of investment in locally planned projects suggests that transmission owners in some regions may be directing investment to such projects, with the result that potentially more efficient or cost-effective facilities are not considered,” APPA said.

But the problems vary by region and even between neighboring transmission owners so FERC should be flexible if it moves forward with any rule changes, the public power trade group said.

Advanced Energy United said local projects lead to fewer benefits than the major regional lines that are needed to help decarbonize the power system.

FERC “should aim to ensure more effective oversight of local transmission projects and more efficient regional and interregional transmission planning such that regional projects and/or non-wires alternatives and grid-enhancing technologies are selected over local projects when doing so would increase the benefits of transmission buildout while reducing total transmission costs,” said AEU.

More information sharing about such projects would help ensure that the money is being spent prudently and aid states in assessing such projects, AEU added. Setting up independent transmission monitors could help deal with the information asymmetry by providing independent analysis for all stakeholders, it said.

A joint filing of groups calling themselves the “Electricity Customer Alliance,” included several state consumer advocates from PJM, the Citizens Utility Board of Illinois, Electricity Consumers Resource Counsel, Public Citizen and the R Street Institute.

“Transmission developers have ample access to capital and spend over $20 billion per year on transmission in the United States,” the groups said. “Unfortunately, billions of dollars are misallocated annually, eroding net benefits to consumers and suppressing development of cleaner and lower-cost generation.”

FERC’s regional planning NOPR proposed pulling back on transmission competition by giving utilities the right of first refusal over transmission projects if they team up with another firm. But the groups said that would not bring their dollars out of the local process and into the regional planning process.

The Environmental Defense Fund, Natural Resources Defense Council, Sustainable FERC Project, Sierra Club and other environmental groups filed joint comments saying the current lack of oversight means FERC cannot ensure that transmission rates are just and reasonable.

“The current Order No. 890 requirements are insufficient to ensure a transparent process where stakeholders have a meaningful opportunity to examine system needs, evaluate public utility transmission providers’ proposed solutions, or propose potential solutions that can more effectively address these needs,” the groups said. “In practice, these requirements are treated like suggestions that are neither binding nor sufficiently detailed to elicit proper behavior from public utility transmission providers.”

Independent power producers NRG Energy (NYSE: NRG) and LS Power argued that while spending on transmission has been on the rise, it has not been for the major projects needed to transform the grid. In addition to developing generation, LS is active in competitive transmission development. NRG said the 5.5 million customers of its retail power business have seen their delivery charges rising in recent years.

“By removing the pass-through regulation that has come to characterize formula ratemaking in this field from its application to certain transmission rate base, the commission can return to the basic principles of sound utility regulation while achieving the public policy goals that animate much of its recent transmission rulemaking activities,” NRG and LS said.

They said FERC should put all projects at 100 kV and above into regional planning processes, a position LS Power has had for years.

Formula rates allow transmission owners to put new transmission investment into their ratebase with a presumption that it is just and reasonable. FERC could limit the type of lines that are put into formula rates to those that face competition, or additional regulatory oversight, or could even eliminate the practice altogether, NRG and LS said.

Utilities Say Local Spending is Justified

Formula rates are transparent and offer oversight, along with the benefits of administrative efficiency and allow for timely recovery of costs, said the Edison Electric Institute.

If any regulatory gaps exist, EEI said, the planning processes vary so much by region that FERC should not force universal fixes. Order 890’s rules for supplemental projects already offer sufficient transparency, it said.

The issue of smaller lines taking precedent has often come up in PJM, but Exelon told FERC there is good reason for the recent increase in spending in supplemental projects there.

“During the 2010s, PJM faced historically low load growth and had just experienced a build cycle of natural gas units, which had the effect of moving significant new, low-cost generation closer to load centers, reducing congestion,” Exelon said. “While these factors moderated the need for regional projects, during this period PJM identified, and PJM transmission owners developed, more than $20 billion in regional projects.”

Local projects needed investment in the same period as many lines reached the end of their useful lives and others needed maintenance, said Exelon (NASDAQ:EXC).

FERC should focus on the other changes it has considered — including the shift to forward-looking, scenario-based planning and first-ready/first-served queue processing — because the regulatory changes implied by its request for comments would amount to “experimentation” and might only delay needed investment in transmission, the company said.

American Electric Power (NASDAQ:AEP) agreed with Exelon that age is a major factor in rising transmission spending, saying 27% of its transformers and 10% of its circuit breakers are expected to exceed their life expectancy in the next 10 years.

“This reveals the simple fact that assets, some of which exceed 100 years old, have now reached the end of their useful life and need to be replaced to ensure the continuing reliability and resilience of the system,” AEP said.

AEP joined other transmission owners in questioning whether independent transmission monitors are needed, warning they could delay the transmission buildout without producing any real benefits.

The New York Transmission Owners do not want FERC to impose any national fixes because they could put a wrench in their efforts working with the state and others to implement the Climate Leadership and Community Protection Act that requires the state to have net zero emissions by mid-century. Because NYISO is in a single state, the local projects that have generated controversy in PJM are highly transparent there and regularly updated publicly with NYISO, the transmission owners said.

RTOs Weigh In

ISO-NE told FERC that its states have already asked for some reforms on “asset condition projects,” and its stakeholders should be allowed to work on that process.

Such projects are like PJM’s supplemental lines and generally fall under transmission owners’ responsibilities, but in New England projects above $5 million have to go the ISO’s Planning Advisory Committee.

PJM filed comments saying that FERC has found its supplemental transmission process provides enough transparency to stakeholders and reaffirmed that when the same rules were extended to end-of-life projects.

All stakeholders, including state regulators, can ask questions during its “Attachment M3” process for local planning.

“PJM currently has processes in place pursuant to which a PJM TO or incumbent developer constructing either a [regional] baseline project approved by the PJM Board of Managers or an Attachment M-3 Project provides reports to PJM, which allows PJM to track the project’s scope, schedule and any cost increases,” the RTO said.