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November 14, 2024

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SERC Board of Directors Briefs: Dec. 14, 2022

CHARLOTTE, N.C. — SERC Reliability’s Board of Directors meeting on Thursday at times resembled an impromptu farewell party, as multiple attendees took time from their presentations to say goodbye to departing chair Todd Hillman.

But the gathering was a serious affair too, with stakeholders reflecting on the many challenges facing the bulk power system as the year ends. In his opening remarks, CEO Jason Blake reflected on the Dec. 10 shootings that severely damaged two Duke Energy substations in Moore County, North Carolina, and plunged around 45,000 customers into darkness. Duke worked around the clock following the shootings and had restored all affected customers by last Wednesday. (See Duke Completes Power Restoration After NC Substation Attack.)

“Sometimes you have these moments that occur, that really bring home the impact that we all have, and … especially for those of you that [have your hands] directly … on the controls, the importance of that work,” Blake said. “These things are always sobering reminders of how hard we work to stay ahead of the game and how we constantly have to understand and also digest these events to see how we can improve.”

SERC BoD 2022-12-13 (RTO Insider LLC) Alt FI.jpgAttendees at SERC Reliability’s Board of Directors meeting in Charlotte, N.C. | © RTO Insider LLC

 

Investigators have not identified any suspects or motivation for the attacks and have dismissed connections to a later incident in which gunshots were heard outside a Duke hydroelectric station in South Carolina. Blake noted that, while power failures are nothing to celebrate, the fact that the outages remained limited to Moore County with no cascading impacts on the broader electric grid was a marker of how quickly and effectively Duke responded to the crisis.

“The system, as designed, performed. But that said, we still always want to take note of these occurrences and see what we can learn, and are there opportunities to better ourselves,” Blake said.

Risk Report Approved

Looking ahead to the new year, board members approved SERC’s 2023 corporate strategic initiatives and key performance objectives, along with a supplemental contribution to employees’ 401k accounts for 2022. The board also voted to accept the regional entity’s 2022-23 Regional Risk Report.

Compiled by SERC’s Risk Committee, the Regional Risk Report aims to identify the top 10 risks facing the region’s power grid, grouped into “managed” risks, for which mitigation plans need to be developed and implemented, and “monitored” risks, where mitigation plans and guidance already exist.

The group in which a risk is placed does not necessarily reflect its priority level. Next year’s “monitor” list includes extreme weather, which is ranked fifth on the overall list, along with variable energy resource integration and parallel/loop flow issues, ranked ninth and 10th respectively. Risks on the “manage” list include supply chain vulnerabilities, shortage of required skillsets, resource uncertainty, and deliberate disruptions such as sabotage and attack — respectively ranked first, second, third, and seventh.

NGC Describes Leadership Shuffle

Sunflower Electric Power Corp. chose Hillman — who was also MISO’s senior vice president and chief customer officer — as its new CEO earlier this year. (See Sunflower’s New CEO Hillman Looks Back on MISO Tenure.) Hillman will take his post on Jan. 16, succeeding Stuart Lowry, and will depart SERC on Jan. 3, two years and two days after taking his seat as chair.

Because of Hillman’s early departure, Vice Chair Lee Xanthakos of Dominion Energy agreed to the Nominating and Governance Committee’s (NGC) request that he step up to chair early, with the board assenting. Under ordinary circumstances his term would have begun next May; instead, he will take office Jan. 4, with his term ending May 31, 2025.

With Xanthakos moving up to chair, the NGC nominated Lisa Johnson of Seminole Electric Cooperative to succeed him as vice chair. Directors approved the choice unanimously, along with the proposal to nominate Lonni Dieck to another term as lead independent director, concurrent with Xanthakos and Johnson.

To replace Director Arnold Singleton, who left the board in September, the committee suggested former director Bob Dalrymple of the Tennessee Valley Authority, which the board also approved. Upon confirmation by SERC’s membership at their March 29 meeting in Fort Lauderdale, Fla., Dalrymple will serve out the remainder of Singleton’s term, ending May 31, 2023. Dalrymple will serve as the federal-state sector representative and will also join the NGC.

Committee Chair Tim Lyons also informed directors that the NGC has opted not to conduct a search for additional independent directors beyond Dieck, Shirley Bloomfield, and Deborah Wheeler, who joined the board as its first independent members in 2021. Lyons had floated the possibility of more independent directors at the board’s last meeting in September but said Thursday that the committee does “not believe we are in a position to move forward with another independent director search at this time.” (See “More Independent Directors a Possibility,” SERC Board of Directors Briefs: Sept. 22, 2022.)

Board Honors Hillman

The board voted through a resolution thanking Hillman for his 14 years both as board chair and as a director.

Hillman presided over SERC’s transition to a new organizational arrangement in 2021, with the RE adopting a membership structure and welcoming its first set of independent directors. Reflecting on the changes during his tenure, Hillman praised the organization for its performance under the new structure and said it had “really stood out as a leader in the ERO space.”

Todd Hillman Award 2022-12-13 (RTO Insider LLC) Alt FI.jpgHillman, second from right, poses with a plaque and “Top Banana” award honoring his service as chair. | © RTO Insider LLC

 

“I look at the SERC of today, [and] I see servant leaders. I see SERC at the center; I see people really trying to move that forward,” Hillman said. “But I think the full measure of the experience is the value of the relationships and the friendships created. So I want to thank you all for those.”

Blake also presented Hillman with a plaque in honor of his years as chair, along with the organization’s recently inaugurated “Top Banana” award, first given to Dalrymple upon his departure at SERC’s March board meeting. Dalrymple joked on Thursday that one of his conditions for returning to the board was that he not be required to return his award.

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NERC Standards Committee Briefs: Dec. 13, 2022

2023-25 Strategic Work Plan Approved

The NERC Standards Committee on Tuesday approved its 2023-25 Strategic Work Plan, which it says reflects “the transition of the standard development process to primarily address a small number of FERC directives, emerging risks and process improvements.”

The plan has three “focus areas.”

  • Process Improvement: The committee will conduct periodic reviews of existing processes to promote continuous improvement. The chair and vice chair will lead an initiative to implement the Board of Trustees’ recommendations to improve the standards development process in conjunction with NERC staff, other standing committees and the Standing Committee Coordinating Group (SCCG). In addition, the SC and the Compliance and Certification Committee (CCC) will convene a joint task force in early 2023 to evaluate the existing standards grading process and identify opportunities for improvement. The review will be in lieu of the annual standards grading exercise.
  • Risk Mitigation: The SC will work with NERC staff and the SCCG to prioritize standards development projects based on reliability risk. It will continue participating in “feedback loops.”
  • Standards Quality: The work plan says reliability standards “should be clearly written, effective in mitigating risk to the [bulk power system] and not unnecessarily administratively burdensome.” The SC will seek to resolve an outstanding FERC directive through Project 2020-04 (Modifications to CIP-012 regarding the availability of communication links and data communicated between bulk electric system (BES) control centers) and a FERC requirement to submit project schedules for one ongoing Critical Infrastructure Protection (CIP) project. The Project Management and Oversight Subcommittee (PMOS) and NERC staff will identify and schedule periodic reviews for SC endorsement. The PMOS will use the most recent standards grading results to prioritize and schedule by the end of the first quarter of 2023. The SC will continue to review guidelines and technical basis documents for transition to technical rationale documents while moving compliance examples to implementation guidance.

Committee Discusses Proposals to Increase ‘Agility’

The committee received a briefing on recommendations by the newly formed Standards Process Stakeholder Engagement Group (SPSEG). The group was created in May in response to a directive from the NERC board that the ERO find ways to improve its ability to address urgent reliability needs with “agility” while continuing to provide reasonable notice and opportunities for public comment, due process and balancing of interests.

The group submitted its unanimous recommendations for standards process changes to the NERC board on Oct. 10. They include changes to section 300 and Appendix 3A of the Rules of Procedure, as well as recommendations for the standing committees to improve the administration and coordination of standards development.

At the board’s Nov. 16 meeting, it approved resolutions to enact the recommendations. It directed NERC staff to review the Registered Ballot Body for “continued fairness, openness, inclusivity and balance in standards voting” and provide a report on its findings at the board’s February 2023 meeting.

The SPSEG developed several recommendations for the SC on administering the standards development process, saying the committee should:

  • appoint a single drafting team to address both the standards authorization request (SAR) and standard development phases of a project;
  • provide guidance to drafting teams on the role of the SAR in the standards development process;
  • increase the efficiency of how it administers the SAR phase for projects eligible to be posted for informal comment or those that must be posted for formal comment;
  • revise its charter and make other changes to improve efficiency; and
  • revise its guidance to drafting teams regarding the development of implementation guidance and compliance elements.

The SPSEG also recommended changes to the SCCG to take advantage of cross-functional expertise and provide feedback loops. It called for revising the SAR form to provide greater clarity on the need for new projects; aiding in project prioritization; and expanding participation in the standards quality review process.

Finally, it recommended that the Reliability and Security Technical Committee increase the transparency and stakeholder awareness of its process for endorsing draft SARs.

Philip Winston, who is retired from Southern Co., questioned how the SC should respond to the recommendation that it provide drafting teams with guidance on the role of the SAR.

“In the past … we’ve been clearly told that our role is not to address any kind of technical issues,” he said. “It’s hard to provide … guidance to a drafting team having to do with what’s in a SAR to accomplish the reliability goals without getting into some technical discussion.”

NERC attorney Marisa Hecht responded that the recommendation “is less about the technical components and more about the purpose, [such as] don’t include specific language; leave possibilities open … ensuring that the SAR is a scoping document versus providing” solutions.

Hecht said the recommendations also seek to help in instances in which SAR drafting teams (SDTs) “aren’t quite sure what each section means [and] sometimes come up with different language within the same documents.”

“So I think these are all envisioned to be very procedural and not technical recommendations.”

NERC Vice President of Engineering and Standards Howard Gugel added: “There was a recognition of this group that a lot of the more recent SARs have gotten into the details about how to fix a problem and have not gone into as much: What is the issue for reliability? And why is it an issue?”

Marty Hostler, reliability compliance manager for Northern California Power Agency, questioned why SARs don’t include any cost estimates. “This is a tremendous expense to industry,” he said. “Every entity that operates a utility has to develop budgets. … They have to recover their costs.”

Gugel said the cost estimates come later.

“The SAR lays out problem; it’s not a solution space. So because of that, you don’t really have an idea about what the cost would be until you actually begin drafting the standard,” Gugel said. “That’s why during the comment period for the standard, [NERC asks], ‘Is there a more cost-effective solution than the one that’s being proposed in this language that would still meet the reliability objective?’”

Outgoing PMOS Chief Worries About ‘Churn’

Outgoing PMOS Chair Charles Yeung, famous for his multicolored spreadsheets tracking in detail every project before the ERO, shared his concerns about NERC’s growing workload as he prepared to step down from the post he has held since 2018. He will remain on the subcommittee as vice chair and be replaced by current Vice Chair Michael Brytowski of Great River Energy.

“The volume, the pace, is going to be probably one or two of the biggest concerns going forward,” Yeung said. “There’s a lot of churn — meaning postings and registrations and ballots and comments.

“The workload has grown. And the importance of the work is growing as well … things like cold weather, energy assurance, [inverter-based resources] — those are all new horizons of reliability.”

Yeung project status report (NERC) Content.jpgCharles Yeung, who has headed NERC’s Project Management and Oversight Subcommittee since 2018, uses a multicolored spreadsheet to keep track of ongoing projects. | NERC

Yeung said he asked other PMOS representatives whether keeping pact was causing stress on their resources. “There was a resounding ‘yes.’”

He added, “Most PMOS reps feel like their companies are keeping pace, but there is concern about the quality of the feedback that’s going back to the Standards Committees because of the workload.”

Project 2022-04 SDT

The committee voted to endorse NERC staff’s recommendation to appoint 13 members to the SDT for Project 2022-04 (EMT Modeling). NERC received 34 nominations; two of the candidates later withdrew.

Supplemental Nominations to Project 2020-04 SDT

The committee voted to solicit additional SDT members for Project 2020-04 (Modifications to CIP-012), whose membership dropped from nine to five following four resignations.

2023 Executive Committee Nominations

The committee invited those interested in serving on the SC’s five-member Executive Committee (SCEC) to submit their biography via email to the committee secretary; Chair Amy Casuscelli, of Xcel Energy; and Vice Chair Todd Bennett, of Associated Electric Cooperative Inc., by Jan.  9.

The committee will select members for one-year terms at its Jan. 25 meeting.

2023 Standards Committee Meeting Schedule

The committee will hold eight conference call meetings in 2023 in addition to four in-person gatherings:

  • March 22 in Little Rock, Ark. (SPP), 10 a.m. to 3 p.m. ET;
  • July 19 in St. Paul, Minn. (MRO), 10 a.m. to 1 p.m. MT (followed by a joint meeting with the CCC at 1-4 p.m.);
  • Sept. 20 in D.C. (NERC), 10 a.m. to 3 p.m. ET; and
  • Dec. 13 in Atlanta (NERC), 10 a.m. to 3 p.m. ET.

Standards Committee Process Subcommittee Elects Leaders

SPP attorney Matt Harward, who assumed the chairmanship of the Standards Committee Process Subcommittee after the resignation of the previous chair in July, was elected by the committee last month to continue leading the group for 2023-24.

Troy Brumfield, regulatory compliance manager for American Transmission Co., was elected vice chair, also for a two-year term.

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NECA Panelists Talk Capacity Market, DERs

A panel of energy experts took ISO-NE’s capacity market to task last week, lambasting the region’s Forward Capacity Market and offering ideas about how to improve it.

The panel at the Northeast Energy and Commerce Association’s Power Markets Conference, held Dec. 5, was titled “Can Markets Get Us More Reliable?”

And while the answer from the group wasn’t an unconditional “no,” it involved heavy criticism for the way the capacity market is currently set up.

“I’ve always viewed forward capacity markets as the original sin of market design,” said William Hogan, a professor of global energy policy at Harvard University.

“I know it’s politically embedded in the system … but I don’t think they’re a solution to any real problem other than mailing checks to people,” Hogan said.

When it comes to ISO-NE’s markets specifically, Sheila Keane, director of analysis at the New England States Committee on Electricity, said that there’s a lack of a “clear measurement or goalpost” for energy adequacy.

“If we’re thinking about changes to the capacity market, that’s something the states are always open to having discussions [about],” she said.

David Patton, president of Potomac Economics, ISO-NE’s External Market Monitor, said the FCM isn’t a viable solution to most of the problems that New England’s grid faces.

“It’s not a very good solution for resource adequacy to begin with, but when you start to look at some of the challenges we’re facing with reliability and the introduction of intermittents, it becomes less and less reliable,” he said.

And Ben Griffiths, regulatory policy director at LS Power, rounded out the critique with an academic bent.

“On the capacity market side, there is not enough liberal arts thinking,” he said. “It’s not clear to people what they’re actually buying, or what [the 1-day-in-10-year loss of load standard] is actually doing.”

DERs and Blurred Lines

On a later panel, titled “Blurring of Wholesale and Retail Lines,” experts laid out the importance of distributed resources for the energy future, and of markets and pricing that help incentivize them.

Greg Geller, head of regulatory affairs at Enel North America, laid out a bevy of benefits from greater DER utilization in New England, including reduced transmission costs, better price signals for emissions reduction, help with winter reliability issues and more.

But to do that, the region needs strong and flexible retail programs, the panelists said.

Part of the challenge is that different entities regulate overlapping spaces, said Caitlin Marquis, director of Advanced Energy Economy.

That’s been demonstrated by the compliance process for FERC Order 2222, which requires RTOs and ISOs to provide DERs access to wholesale electricity markets.

“The compliance directive was on the ISO, not on the states or retail regulators — but they have an important role in implementing pieces of Order 2222,” Marquis said.

ISO-NE is thinking carefully about how to integrate demand resources in the region, said Henry Yoshimura, the grid operator’s director of demand resource strategy.

“What do we need? Retail rates that reflect time-varying costs,” he said.

“Retail prices should be high when marginal costs are high and should be low when they’re low,” Yoshimura added.

Without the right rate design, he said, “you’re never going to get the right demand flexibility” from DERs and other such resources.

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NYISO Over-crediting Poorly Performing Units’ Capacity, Monitor Says

NYISO is qualifying generation units for meeting their reserve requirements even though they fail to provide adequate reserves during normal market operations, the ISO’s Market Monitoring Unit told stakeholders Tuesday.

Speaking to the Installed Capacity/Market Issues Working Group, Potomac Economics’ Pallas LeeVanSchaick said NYISO is using capacity accreditation rules that may be awarding excessive accreditation to several gas generators. The ISO should re-evaluate its reserve auditing procedures for gas turbines to be more responsive to normal market operations and improve capacity accreditation test requirements to account for peak summer conditions, he said.

The Monitor’s third-quarter report on the NYISO markets, released last month, found that the ISO is conducting more 10- and 30-minute non-synchronous reserve pick-up (RPU) audits but has failed to disqualify gas turbines that performed poorly.

Gas Turbine Audits (Potomac Economics) Content.jpgGas turbine audits show inability to accommodate normal reserve requirements. | Potomac Economics

 

Potomac studied the 13 worst performing gas turbines; despite many of them being consistently used by the ISO, they regularly fail to achieve performance levels even close to the 89% average of all other gas turbines.

Kevin Lang, partner at Couch White, asked why Potomac believed the ISO was not acting on generators that had performed poorly in audits.

LeeVanSchaick responded that “NYISO has the authority to do that … but it is not clear to us why they have not been disqualified.” Potomac will “monitor this because there’s inefficiency in continuing to compensate resources for providing reserves when they cannot perform.”

According to the report, on days when peak load surpasses 28 GW, an average of about 1,060 MW of installed capacity from fossil fuel and nuclear generators was functionally unavailable during the quarter because of above-average temperatures.

Functionally Unavailable Capacity (Potomac Economics) Content.jpgFunctionally unavailable capacity from generators during peak conditions | Potomac Economics

 

Emergency generators dispatched by NYISO during peak load may overestimate their available capacity and receive improper accreditation because these units’ dependable maximum net capability (DMNC) tests, which calculate the gross sustained net output of a generator, fail to capture ambient water temperatures, LeeVanSchaick said.

The audit results suggest “that there is a tendency to over-credit resources that are impacted by ambient conditions,” he said. On peak summer days, “there is capacity that, although qualified, is not as effective as other capacity in terms of providing reliability,” meaning “some units are going to be less available at peak times.”

Howard Fromer, who represents the Bayonne Energy Center, asked whether Potomac had begun discussions with NYISO to adjust capacity accreditation procedures or rules for the impacted resources.

LeeVanSchaick said that Potomac “certainty recommends NYISO looks at these categories in the context of capacity accreditation efforts.” (See “Capacity Accreditation,” NYISO Justifies Unpopular 10-kW DER Aggregation Min. Requirement.)

NYISO energy markets were competitive throughout the quarter, according to the report. Energy prices increased across all zones because of both higher congestion in the Central-East interface and emissions costs, and capacity prices fell because of lower installed reserve margins and peak load forecasts, which helped offset increased spot prices.

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Inslee to Seek $10M for Energy Research Program in Central Wash.

Washington Gov. Jay Inslee said Monday he will seek millions in state funding to establish a program at Washington State University’s Tri-Cities campus dedicated to researching sustainable energy.

Inslee said he plans to ask the state legislature in January for $10 million to fund the Institute for Northwest Energy Futures at WSU’s Richland branch. 

The work to launch the institute began last year when a now-deceased longtime supporter of the school donated $500,000 toward an endowment to fund the salary for the director of the institute. No other donations have since followed, Chris Mulick, WSU director of state relations, told NetZero Insider. 

With funding from the state, WSU would likely lease a building near the Richland campus for the institute, Mulick said. The institute plans to hire a director in its first year, and scientist faculty members in the second year after legislative approval. 

The faculty would be split with five at the Richland campus and three at WSU’s main campus in Pullman. Each faculty member would have a graduate assistant. Some ancillary employees would also be hired. The Richland campus currently has about 100 faculty members. 

Of the $10 million, $2 million would go into an endowment to pay the salary of the institute’s yet-to-be-hired director.

“I’m cautiously optimistic about legislative support for this idea,” Inslee said at a press conference in Richland.

Richland is also home to the Pacific Northwest National Laboratory, the Hanford nuclear reservation and many small engineering and research firms. Consequently, Inslee believes the city is good place for the institute to interact with Richland’s huge scientific and engineering community. The area is also home to research on nuclear, solar, wind and other alternative types of power.  

“There is no one technology that we’re going to bind ourselves to as the exclusive game in town,” Inslee said.

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Stakeholder Soapbox: A Transmission Planning Resolution Emerges

Devin Hartman (R Street Institute) Content.jpgDevin Hartman, R Street Institute | R Street Institute

By Devin Hartman and Kent Chandler

For more than a year, FERC, state authorities and industry stakeholders have agonized over the performance of transmission planning. The most notable forums include the Joint Federal-State Task Force on Electric Transmission and FERC’s October 2022 technical conference.[1],[2] The only reform action to date has been a Notice of Proposed Rulemaking on regional transmission planning issued by FERC last April, with a final rule in sight for early-to-mid 2023.[3]

These processes have revealed troubling flaws in transmission federalism. Moving forward, three principles should guide transmission planning reform:

  1. Durability. Reforms must be legally and politically robust to secure a stable regulatory climate.  
  2. Quality governance. Local and regional transmission planning are co-dependent, meaning they require synchronization between state and federal regulators with clear roles and responsibilities for each. Proper transmission planning also requires independent administration and monitoring.
  3. Sound economics. Planning should be proactive, incorporate all technological solutions, and maximize net benefits to consumers. Procurement should be competitively bid wherever possible and regulatory scrutiny should fill in gaps where competition is unworkable.

Current transmission planning does not embody these principles. The consequences are higher-than-necessary costs, stifled innovation, diminished reliability and prolific controversy. FERC Commissioner Mark Christie recently observed that transmission capital expenses have nearly tripled between 2012 and 2020.[4] Feeling this pain, dozens of consumer groups have called for better governance, planning and competitive procurement.[5]

Repairing Current Frameworks 

The economic disappointment and extensive controversies surrounding transmission development should come as no surprise: They directly reflect the institutions and policies underlying transmission planning and procurement. FERC Orders 890 and 1000 have good bones, but framework adjustments along with fixing key implementation flaws are paramount. For example, the same rules ostensibly exist regardless of regional transmission organization (RTO) membership, but two sets exist in practice — one in RTO regions and another outside them — creating untenable governance issues.

The current regional transmission framework is reactive, miscounts transmission benefits, excludes some technologies from consideration and plans economic and reliability projects in artificial silos. Astoundingly, a large proportion of transmission development is neither subject to competitive bidding nor economic regulation. Competitive exemptions are too frequent in RTO footprints, while competition is non-existent outside RTOs.

Where competition is absent, gaps in regulatory oversight remain pervasive. FERC’s formula rates for transmission, coupled with the presumption of prudence, is not economic regulation. Meanwhile, not many states have full authority to approve or review transmission projects, and even fewer state commissions play a meaningful role in the planning of transmission facilities.[6] Projects in the 100-230 kilovolt (kV) range, those creatively dubbed “reliability need,” or those within a single transmission zone, regardless of cost allocation, often fall between the cracks.

In Order 1000, FERC declined to remove a federal right of first refusal for local transmission, out of consideration for incumbent utilities’ retail “service obligation.” However, since Order 1000, billions of dollars of local transmission have been built by affiliates of incumbents, without having a service obligation themselves.[7] These projects are exempt from competition. State utility commissions have little-to-no jurisdiction over them. And their costs are often allocated across state lines.

Further, it is hardly fair to consider transmission between 100 and 230 kV “local” given the increasingly regional nature of those facilities. Between February 2020 and July 2022, the Kentucky Siting Board approved certificates for 20 merchant solar facilities, between 40 and 250 MWs), with an average size of more than 100 MW.[8] All of the projects propose to build or connect to transmission below 200 kV, and only one-fifth of the projects are being built to provide power to Kentucky utilities, while the rest will serve customers across the Tennessee Valley Authority, MISO and PJM footprints.  

At above-market rates of return, it is no surprise that incumbent utilities have prioritized building out transmission where competition and regulatory oversight are virtually absent. In doing so, they typically pursue inefficient small projects in lieu of more efficient technologies and subvert the planning of more efficient alternatives at the regional level.[9] In some regions, the majority of transmission projects skirt competition and robust regulatory review, and the number is growing.[10]

Repairing all this requires governance and economic reforms to work in tandem, augmented by stakeholder buy-in. Three reform priorities are:

  1. Improve the Order 890 and 1000 frameworks. Equalize the application of Orders 890 and 1000 across RTO and non-RTO regions. All regional transmission should be independently planned. RTOs provide this function, but accomplishing this objective outside RTOs would require an independent transmission planner. Regional transmission planning must account for public policy effects on generation, including anticipated retirements based on plant economics, and not wait for deactivation notices to be submitted.  
  2. Make regional transmission planning proactive and holistic with enhanced competition. Planning should reflect the multi-decade nature of the investment, incorporate commercially available technologies, and account for the full suite of economic and reliability benefits simultaneously, not in silos. Minimizing competitive exemptions is crucial, with options including stricter “reliability need” exemptions and lowering the voltage exemption threshold to 100 kV to comport with the standard definition of the bulk power system.[11] This would clarify for states the scrutiny that some projects undergo.
  3. Ensure economic oversight where competition is unworkable. Utility projects exempt from competition must face economic scrutiny from regulators, which warrants reexamining the policy of unconditional formula rate treatment under a presumption of prudence. Need and prudence are impossible to judge without information. State regulators note that an independent transmission monitor (ITM) could furnish such information and help close the regulatory gap with local transmission projects.[12] It could also help ensure Order 890 compliance.   

Reform Agenda

Transmission reforms are as entangled as the bulk power system. Yet many reforms will be pursued through disparate procedural vehicles, which elevates coordination risk.

FERC’s first bite at the apple is its forthcoming final rule on transmission reform. The winning formula is for FERC to jettison the anti-competitive provisions of its proposed rule while refining the good ones, including the longer-term planning horizon, what advanced technologies to include in planning, holistic benefits accounting and breaking down silos between “economic” and “reliability” project planning.[13]  

FERC will need to pursue the remaining reform agenda through separate proceedings. The October technical conference established a record upon which to prioritize governance improvements, including the role of independent monitoring and planning, as well as pathways to expand competition and close the regulatory gap for projects where competition is unworkable. This could spin off into any number of dockets. The trick will be connecting the dots.

Devin Hartman is director of energy and environmental policy for the R Street Institute.

Kent Chandler is the chairman of the Kentucky Public Service Commission. 

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Granholm: Sustained Fusion May be Possible Within a Decade

The results of more than 60 years of effort at a federal laboratory charged with ensuring the reliability of U.S. thermonuclear weapons could give the nation the ultimate weapon to fight climate change with a technology capable of producing carbon- and radiation-free energy.

White House and defense policymakers joined Energy Secretary Jennifer Granholm on Tuesday and a research team from Lawrence Livermore National Laboratory to provide a few details of the technology that researchers developed to pull off a global first: less than one second of controlled hydrogen fusion that created more energy than had been required to initiate it. (See related story, DOE to Announce Major Advance in Fusion Technology.)

That’s the same kind of reaction that powers stars, including the sun. And it’s the same physics at the heart of a hydrogen bomb.

“We got out 3.15 megajoules. We put in 2.05 megajoules in the laser,” explained Marvin Adams, Texas A&M nuclear engineering professor and deputy administrator for defense programs at the Department of Energy. “That’s never been done before in any fusion laboratory anywhere,” he said in a detailed panel discussion that followed the official announcement.

The experiment involved focusing the light of powerful lasers on a tiny capsule suspended inside a glass cylinder. The capsule, about the size of a peppercorn or half a BB, contained isotopes of hydrogen. The force of the lasers, which had been converted to X-rays, compressed the hydrogen isotopes to the point at which they merged, releasing the energy in the form of heat.

The entire experiment — energizing 192 of the most powerful lasers on the planet — required more than 300 megajoules, said Adams.

That meant that powering up the lasers took a little over 83 kWh of electricity — not exactly an energy hog, but still far more power than produced in the small capsule in which the fusion occurred. In 2021, the average monthly residential power consumption was 886 kWh, according to Energy Information Administration.

“The laser wasn’t designed to be efficient,” Adams quickly added. “The laser was designed to give us as much juice as possible to make this incredible condition possible in the laboratory. There are many, many steps that would have to be made in order to get to inertial fusion as an energy source.”

Granholm noted that the Biden administration’s goal is to develop a commercial fusion reactor within 10 years. “This demonstrates that it can be done,” she said. “That threshold being crossed allows [researchers] to start working on better lasers, more efficient lasers, on better containment capsules — the things that are necessary to allow it to be modularized and taken to commercial scale.”

The strategy at LLNL has been based on using the powerful lasers not only to jumpstart fusion but also to control the reaction after it has begun with the pressure of the beams themselves.

The resulting “inertial confinement fusion” not only relies on the pressure of the laser beams to force hydrogen isotopes close enough together to initiate the fusion but also to confine the resulting explosive results in order to create conditions for a controlled but continuous fusion.

The fusion produces enormous amounts of heat that could be used to produce steam to power turbines and generators just as commercial fission reactors operate today.

There are several private research and development companies that are working to develop fusion reactions controlled by extremely powerful magnets rather than the force of lasers. California-based TAE Technologies has developed fusion experiments creating and magnetically controlling 135 million-degree plasma. (See TAE: Fusion Reactor Controls 135M-degree Plasma.)

TAE’s goal is to build the hardware and a process to produce 180 million-degree plasma, the point at which fusion can continue, again controlled by ultra-powerful magnetic fields.

General Fusion, a Canadian company, earlier this week announced it had achieved a milestone: controlling the superheated plasma with compression alone for brief periods rather than with magnetic fields or lasers.

LLNL Director Kim Budil said the competing technologies will “feed off each other” in the future. “Many technologies will grow out of both fields in addition to the path to a fusion power plant. I think having both [technologies] is important.

“If we could not ignite capsules in the laboratory, you could not see a pathway to an inertial confinement fusion energy plant,” she said. “So this was a necessary first step.” She noted that the laser array at the lab “was built on 1980s laser technology.”

“We need to bring modern technology approaches to the drivers. We need to think about all the system questions.”

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AES Ohio Proposes $145M Project for EV Manufacturing Loads

AES Ohio (NYSE:AES) presented the PJM Transmission Expansion Advisory Committee on Dec. 6 with a $145.1 million supplemental project to build two new substations and 13 miles of double circuit 345-kV lines to meet over 1,000 MW in expected load growth from electric vehicle manufacturers in the Jeffersonville area. The area is currently only served by a radial 69-kV extension.

The proposed solution would expand the planned $27 million Madison substation, which is to be built along the Green-Beatty 345-kV line, with a new 345-kV substation. The expansion would step down to 69 kV to feed into the South Charleston substation and also have four 345-kV line exits.

The Fayette Substation would become the primary source for the region, stepping down from 345 kV to 138 kV and 69kV. It would include a quarter-mile 138-kV extension to serve a 140-MW committed development. It is estimated to cost $33.9 million. Adding 13 miles of double circuit lines to connect it to the Madison substation would cost an estimated $51.2 million.

“This substation is located central to the largest developing load center in the AES Ohio area supporting the electric vehicle manufacturing industry developing in the area,” the AES presentation says.

A 69-kV line from the Fayette substation would run approximately 1.5 miles to the new Panther substation, which is proposed to replace the existing Jeffersonville 69-kV substation — which is located in a floodplain and impractical to expand any further. The new substation, designed as a “69-kV breaker and a half station” would step down to 12 kV.

The Panther substation comes with a projected $15.5 million cost, while the 69-kV line and rerouting around 5.5 miles of lines from Panther to the existing Octa substation, which was previously connected to the Jeffersonville substation, is estimated to cost $17.5 million.

The project would add to an existing supplemental project, S0323, that would construct a 69-kV line from South Charleston to Jeffersonville. AES said the expected load exceeds the capabilities of that line.

Other Supplemental Projects

  • PECO (NASDAQ:EXC) has proposed to upgrade obsolete relays, communication and metering equipment, as well as remove a wave trap on the Heaton-Jarrett line in Montgomery County, Pa. The estimated cost is $1.77 million with an in-service date of April 1, 2023.
  • Dominion Energy (NYSE:D) has identified three facilities with low voltage issues caused by a contingency with the loss of two lines in Norfolk, Va.
  • Dominion submitted a distribution point request for a new substation, which would be named Edsall, servicing a total load of approximately 100 MW in Fairfax County.
  • Dominion also submitted a request for a distribution request for a new substation, to be named Tropical, serving a data center campus with a load over 100 MW in Henrico County. The requested in-service date is Jan. 1, 2025.

Generator Deactivation Update

PJM has determined that there are no reliability concerns associated with a deactivation request from a 14-MW Lorain County landfill facility, which has requested to go offline on April 1, 2023, according to Phil Yum of PJM’s system planning modeling and support department.

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New York CAC Debates Inclusion of Blue Hydrogen, Union Jobs in Plan

ALBANY, N.Y. — The New York Climate Action Council (CAC) met Dec. 5 for its penultimate meeting to discuss the final edits to its scoping plan and debate both labor unions and hydrogen resources.

A presentation given to council members highlighted the edits made to the plan since last month’s meeting, but it also included discussion material stemming from previous CAC debates. (See NY CAC Debates the ‘Nomenclature’ of Natural Gas.)

Hydrogen was the most contentious topic at the meeting, with members upset by the inclusion of “low-carbon-intensity” hydrogen as a sustainable form of hydrogen, alongside green hydrogen.

Robert Howarth, professor at Cornell University, the term is “deceptive” and essentially a way of including blue hydrogen in the plan without actually using that term.

While green hydrogen is produced from water split via renewable-powered electrolysis, with oxygen as its only byproduct, blue hydrogen is produced from splitting methane (CH4), with the emitted carbon captured and sequestered. Opponents of blue hydrogen — among whom Howarth is a leader, having authored a paper against it with Mark Jacobson — argue that the process does not result in net-zero emissions, as the methane used is produced from natural gas.

Howarth argued last week that the inclusion of “low-carbon-intensity” hydrogen would enable the “marketing campaigns of the oil and gas industries” to use the CAC’s plan “to argue for the continued use of fossil hydrogen downstream in New York.” Howarth said the council should be “unambiguous when we send messages to the public, politicians and press.”

Paul Shepson, dean of the College of Marine and Atmospheric Sciences at Stony Brook University, agreed that the concept of hydrogen “was once clear [but] is now quite cloudy,” arguing that the CAC has not investigated blue hydrogen and that “lumping” it with green hydrogen is inappropriate.

Raya Salter, executive director of the Energy Justice Law and Policy Center, said the revisions run “absolutely counter” to the CAC’s work and “look pro-fossil fuel industry.” She said it was “shocking” that “the door had been opened to blue hydrogen.”

Mario Cilento, president of the New York AFL-CIO, expressed support for the inclusion of blue hydrogen because “improving reliability, mitigating against extreme cost increases, avoiding job losses and creating job opportunities” was critical to the success of the scoping plan.

New York Public Service Commission Chair Rory Christian disagreed with members’ characterizations of “low carbon intensity,” saying that the term “blue hydrogen” did not appear anywhere in the current scoping plan and that the language “adequately addresses the concerns raised” while still acknowledging that hydrogen has many potential roles to play in energy generation.

‘Family-sustaining’ Union Jobs

Edits to the “Just Transition” chapter of the plan added language recommending that the jobs created be “good, family-sustaining, union” jobs.

Shepson was confused by the added language, saying it sounded like “part of political slogan.”

Cilento responded that the intention was to emphasize that union jobs tend to have better wages and conditions than non-union jobs. Furthermore, a union workforce would be better positioned to help New York, and “it is easier to sustain a family on union wages than not,” Cilento argued.

Shepson, who said he is supportive of unions, replied that “his non-union [job] has been family-sustaining.” He argued that as currently written, the plan appears to imply that only unions can create worthwhile jobs and that the state’s explicit policy is to only support unions.

Elsenbeck was also confused by the language, saying that, although also supportive of labor unions, it was important to encourage jobs in all their forms and that most of the industry workers he interacts with are not in unions.

The CAC will vote on the final scoping plan on Dec. 19, and council members will also be given an opportunity to share any last statements.

The plan will be formally adopted if it receives a two-thirds supermajority approval vote from the CAC. It would undergo an evaluation assessment at least every four years.

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PJM MIC Briefs: Dec. 7, 2022

Limited Support for Co-located Load Proposals

A poll by the Market Implementation Committee last month found little support for two competing proposals on capacity offer opportunities for co-located load — one from the Independent Market Monitor and the other a joint package from Constellation Energy and Brookfield Renewable Partners.

Given the opposition, which comments from the poll suggest cut to the core of the packages, stakeholders last week agreed it would be best to focus on finetuning and clarifying how co-located load not directly interconnected with the grid is treated under the status quo rules. (See PJM Opens Poll on Co-Located Load Proposals)

Currently, generators serving customers who are solely connected to their supply must relinquish a portion of their capacity interconnection rights (CIRs) equal to the amount being provided to the co-located load. 

The Constellation/Brookfield proposal, which received 16% support overall, would have allowed generators serving such customers to retain their CIRs in exchange for the generation capacity remaining available to the grid when called upon — essentially turning the portion of generator serving the co-located load into a peaking unit. Constellation’s Jason Barker said during last month’s special session that the imagined arrangement under the proposal would be a nuclear facility supplying power for highly interruptible load, namely hydrogen electrolyzers.

Poll respondents said they believed that not requiring co-located load to pay for benefits received from the grid — such as synchronized reserve and scheduling — would leave other interconnection customers with having to pick up the cost. Commenters also said the arrangement would effectively allow generators to sell their capacity twice. Those in favor of the proposal said it could prevent generator retirements and the resulting increase in capacity prices and decrease in reliability.

The IMM package would have followed the existing practice of requiring generators to reduce their capacity offer equal to the power draw from the co-located load, while also levying additional charges on the load and administrative requirements on the generator. The proposal received 8% support overall and 9% against the status quo.

Commenters on that plan said they wanted additional details on cost allocation and answers to jurisdictional questions on how the provisions could be implemented. They also expressed concerns about potential overreach into areas addressed by reliability studies. Some respondents said they preferred the package’s stronger accounting for benefits received by co-located load.

Monitor Joe Bowring said the poll results suggest PJM should discontinue discussion of the two proposals and instead focus on clarifying the existing rules. Stakeholders largely agreed Wednesday that co-located loads will continue to exist and that the rules governing their relation to the grid should be clarified.

“While Exelon and other stakeholders are not supportive of the two options on the table, we do think that there would be value in potentially clarifying the status quo rules,” Exelon’s Sharon Midgley said.

Manual Revisions for Day-ahead Zonal Load Bus Distribution Factors Endorsed

The MIC endorsed by acclamation a package modifying how PJM conducts its day-ahead load bus distribution factor analysis and associated manual revisions. The changes still require approval by the Markets and Reliability and Members committees, which will likely vote on them during their January and February meetings.

Under current practice, the RTO calculates the hourly distribution factor for an individual node based on the percentage of state estimator load for that node as of 8 a.m. the prior week. For example, when building estimates for the July 14 market day, data from July 7 at 8 a.m. is currently used for every hour throughout the day.

Under the proposal, distribution factors would be calculated based on real-time data from each hour of the respective weekday of the previous week. So, when looking at 5 p.m. on July 14, data from the corresponding real-time interval on July 7 would be pulled.

The lookback period would use the most recently available day of the week where all 24 hours of data are available, meaning if one hour of data was unavailable for a day in the previous week, data would be drawn from the week before that.

Feedback on Issue Charge, Problem Statement for Combined Cycle Modeling

PJM will be revisiting a proposed issue charge and problem statement on modeling combined cycle units in the market clearing engine to incorporate stakeholder concerns about potentially making market design changes to resolve issues with the scale of the computational challenges.

Concerns raised during the first read of the documents include whether it’s more appropriate and feasible to find a hardware or software solution to the issue, the potential for market power rules to be watered down by switching from multiple schedules per facility to one, and the broad scope of the issue charge.

The current design of the market clearing engine looks at each schedule a generator offers into the energy market as a separate logical resource. While most resources have either one or two, it’s possible for the number to be much higher — particularly for combined cycle units — which exponentially increases the solution time. The problem statement says that a typical 2×1 combined cycle unit would have at least six configurations, meaning that if it offers two schedules into the market, it would be represented by 12 logical resources.

“Based on the last several years of experience with a multi-schedule model in the current MCE and discussions with GE, it is apparent that the multi-schedule model in the MCE with the ECC model will have a significant performance impact that will jeopardize the clearing of the day-ahead and real-time energy markets in the approved clearing timeframe with sufficient accuracy,” the document says.

Paul Sotkiewicz, of E-Cubed Policy Associates, questioned why PJM could not increase its computational capabilities with additional hardware or by using algorithms that can cut down on the number of branches the engine has to compute.

“I don’t think PJM has exhausted nearly all the venues and possibilities, including talking to others who may be more up to date on the more advanced algorithms that are out there,” he said.

Sotkiewicz was also “alarmed” that PJM is seeking to potentially make market design changes with an envisioned six-month timeframe to meet the requirements of a vendor hired without consulting stakeholders. PJM’s Keyur Patel said GE has been hired to develop a market engine product for combined cycle modeling — work it is engaging in concurrently with other RTOs — and aims to begin its PJM work by the end of next year, assuming associated rules have been approved by then.

Patel said PJM re-examines hardware requirements every three to four years and does not believe that hardware or algorithm changes would be enough to resolve the issue.

“There is no other technology available at this point that we can solve it in two hours or [a] two-and-a-half-hour time frame,” he said.

Bowring said the use of multiple schedules for each generator was implemented to provide greater market power protections and that it would be a mistake to revert that change to solve a technical issue at the expense of those protections.

“It’s important not to let a technical issue, as it’s presented, undercut market power mitigation,” he said.

While PJM has considered switching to a single schedule, Patel said other options are on the table as well.

PJM Considering Increasing FTR Bid Limit of 15,000 per Entity

PJM presented a problem statement and issue charge exploring the ability to increase the cap on the number of bids a single corporate entity can place in FTR auctions from 15,000 to 20,000 under quick fix rules, with an endorsement sought at next month’s committee meeting.

The RTO is considering the increase following the transition to weekend on-peak and daily off-peak class types, which has had the effect of requiring two bids to trade the same number of hours of an FTR as prior to the transition, according to the problem statement.

PJM senior engineer Emmy Messina said it may be necessary to delay the increase if the RTO finds that existing technology is insufficient to process the higher number of transactions; however, she does believe those upgrades are technically feasible. 

“I do believe there are ways we can solve allowing for 20,000 bids if we find that the resources don’t look like they can support it today. Maybe it’s getting upgraded hardware,” she said.

Director of Market Operations Tim Horger said he believes PJM can handle the increase to 20,000 bids in a single auction. However, he cautioned against increasing the number too sharply beyond that.

“I do think we need to be careful with opening the floodgates and going [to] 50,000 [or] 100,000 bids. Let’s do this in baby steps,” he said.

DR Worried by Decline in Synchronized Reserve Prices 

Synchronized reserve prices have dropped significantly since the start of October, when new market rules were implemented. Prices were at or below 2 cents/MWh for 95.53% of the hours in October and 97.7% in November, a sharp uptick from previous months. Prices were at those levels 71.81% of the time in September and 36.47% in October 2021. (See FERC Approves PJM Reserve Market Overhaul.)

Synch Reserve Histograms (PJM) Content.jpgSynchronized reserve prices have mostly been below the new offer cap of 2 cents/MWh, which was reduced from $7.50 when PJM overhauled its reserve markets, effective Oct. 1. | PJM

 

“There’s a couple driving factors we believe to be there: One, the offer cap rule going from $7.50 down to the 2 cents, as well as impacts from the must-offer requirement expanding the pool, if you will, of resources that we can procure reserves from,” said Brian Chmielewski, manager of market simulation.

Bruce Campbell, of Campbell Energy Advisors, said that the low prices could push demand response resources out of the synchronized reserve market, which may result in them not being available when the system is tight, even if prices are high.

“There is a concern in the demand response community. … The community is interested in continuing to provide these services, but not interested in providing them for free,” he said.

Chmielewski said PJM is monitoring the price movements and will be providing updated statistics monthly. However, given that market changes are only two months old, it would like to see additional production data before making recommendations for potential changes.

Bowring said the lower prices reflected supply and demand fundamentals and that there is no evidence that eliminating the arbitrary $7.50 adder to offers had any significant impact on clearing prices.