Entergy will have to pay SERC Reliability $60,000 in penalties for violating NERC’s reliability standards, according to NERC’s Spreadsheet Notice of Penalty for September approved by FERC last week (NP22-32).
NERC submitted the Spreadsheet NOP on Sept. 29; in addition to the sanctions against Entergy, the document also details a settlement between ReliabilityFirst and American Electric Power (AEP) carrying no monetary penalty. The commission said on Friday that it would not further review the settlements, leaving the Entergy penalties intact.
Also approved on Friday was a separate settlement involving violations of NERC’s Critical Infrastructure Protection (CIP) standards (NP22-34) for which details have not been released in accordance with FERC’s policy on critical energy infrastructure information, along with a settlement between National Grid USA and the Northeast Power Coordinating Council (NP22-33). (See National Grid to Pay $512k for Standards Violations.)
Entergy Faulted for Maintenance, Ratings Mishaps
SERC’s settlement with Entergy concerns infringements of PRC-005-6 (Protection system, automatic reclosing, and sudden pressure relaying maintenance) and FAC-008-3 (Facility ratings). The entity self-reported both violations after discovering them in 2019, though they began in 2016 and 2017 respectively.
The relevant portion of PRC-005-6 lays out the schedule by which transmission owners, generator owners and distribution providers must maintain the equipment to which the standard applies. Entergy disclosed to SERC that it had missed the mandatory maintenance times on several components.
Among the facilities affected was the underfrequency panel at Entergy’s Turnerville substation near Plaquemine, La. Installed in 2010, the panel should have undergone maintenance on its protective relay within six years, according to the standard, but Entergy said that during an internal audit staff discovered this had not been done because the flag for the panel in its automated maintenance tracking system had been deactivated by an unidentified person.
Similarly, the utility failed to perform maintenance on batteries at the McAdams and Cleveland substations in Mississippi that was required within 18 months of their activation in June 2016 and June 2017, respectively. Again, in both cases the maintenance was skipped because the flag in Entergy’s automated system was disabled.
SERC attributed all three instances to “ineffective internal controls,” blaming Entergy for failing to “require approval for disabling maintenance tasks” in its substation work management system (SWMS). Following the discovery of the issues, Entergy performed an extent of condition review on the SWMS to find any other disabled maintenance flags that might develop into noncompliance; none were revealed. The regional entity said no harm is known to have occurred as a result of the violation.
Entergy’s FAC-008-3 violations were also discovered in 2019 but were unrelated to the PRC-005-6 violations. They concern requirement R6 of the standard, which requires that each TO and GO have facility ratings for their solely- and jointly-owned facilities that are “consistent with the associated facility ratings methodology.”
In August 2019, Entergy discovered an active alarm at its Hartburg substation in east Texas, caused by a failure of a cooling system. The failure had begun in March of that year, but operational personnel failed to schedule maintenance or to lower the rating of the substation — even though the cooling failure required a 20.5% derate.
Following this discovery, Entergy performed an extent of condition review to find any other conditions on the system requiring a temporary rerating. Five more were found; in each case personnel at the utility received alarms of the problems, but “the alarms were set as a low priority and personnel failed to update the facility ratings.” Entergy admitted it was “unaware as to why the alarms were originally set to low priority.”
According to SERC, the root cause of the issue was “inadequate training,” particularly on the part of the Entergy personnel that set alarm priorities, who had not been trained on the importance of the cooling systems and their role in facility ratings. This led other personnel to dismiss the alarms and focus on other tasks that seemed more important. Entergy responded to the issue by updating all alarms to the correct priority and establishing annual training to ensure staff are aware of the components that affect rating of transformers.
In both the PRC-005-6 and the FAC-008-3 violations SERC noted prior noncompliance history. The RE considered the PRC-005-6 history to be an aggravating factor in the penalty determination because the extent of condition review conducted in that case should have revealed the violations covered in this settlement. SERC said these issues also call into question the effectiveness of the mitigation plan of the previous violation, which focused heavily on the ability to disable maintenance flags in the SWMS.
ReliabilityFirst’s settlement with AEP (acting as an agent for several utilities including Appalachian Power Company, Ohio Power Company, Wheeling Power Company and others) concerns violations of COM-002-4 (Operating personnel communications protocols).
The entity reported to RF in October 2020 that it was in noncompliance with requirement R6 of the standard, which details the appropriate response to an operating instruction during an emergency. Specifically, utilities that receive oral two-party, person-to-person operating instructions during an emergency must either repeat the instruction and receive confirmation from the issuer that they understood it, or request that the issuer repeat the instruction.
According to the Spreadsheet NOP, two of AEP’s internal communications during a system event in 2019 were found to be noncompliant with the requirement because operators had “failed to execute three-part communication,” referring to the prescribed responses. RF identified the root case as “lack of process adherence and discipline,” and described the risk posed as moderate.
While the RE noted that failure to communicate properly increases the risk of failure to understand the instruction, it also acknowledged that these were the only two instances of improper communication out of 25 communications that occurred during the event.
RF said it processed the violation as a Spreadsheet NOP instead of a lower-level infraction in order to highlight the importance of proper communication procedure during an emergency. The RE pointed out that unclear communication “has contributed to significant events … that led to instability and cascading outages, including the 2003 Northeast Blackout and the Florida Blackout of 2008.” However, based on AEP’s self-reporting and cooperation in this incident, RF decided not to levy a monetary penalty for its infraction of the standard.
PJM CEO Manu Asthana Warns of Potential Generation Shortfalls
CAMBRIDGE, Md. — PJM CEO Manu Asthana said 40 GW in planned retirements and lagging construction of new generation is raising questions about the long-term reliability of the grid.
“We cannot take the reliability that we enjoy in our region for granted through this energy transition; we have to take concrete steps to ensure that it will continue,” Asthana said during his keynote address for the 2022 Annual Meeting of Members prior to the convening of the Markets and Reliability Committee Oct. 24.
He said about 40 GW of generation is expected to retire by 2030, mostly due to policy decisions rather than economics, leaving PJM without a way to incentivize the units to remain online. On top of that, data centers are expected to add 10 to 15 GW of load, with an unknown amount of growth from electrification.
Approximately 30 GW worth of new interconnection service agreements have been signed this year and there’s an additional 250 GW in the interconnection queue. However, the new generation is lagging the pace of installation that has been anticipated, Asthana said. Of the 30 GW of ISAs signed this year, only 1.5 GW has been built so far.
If the pace of constructing new generation doesn’t ramp up, he said it could lead to more reliance on demand response — with curtailments becoming more commonplace than many DR participants signed up for.
“We have time, but we don’t have time to waste,” he said. “We need to take action to ensure we retain an adequate supply of dispatchable generation through the transition.”
The stakeholder process has proven itself through the challenges of the past several years, Asthana said, and will be essential to navigating the clean energy transition as well.
“I still firmly believe that the way to solve the really complex problems of the energy transition is together as a stakeholder body. Not because it’s the quickest way to get there … but because it’s the best way to get to a resilient, durable and lasting set of solutions.”
Black Start Fuel Requirements Advance to Members Committee
PJM stakeholders endorsed a slate of revisions to the tariff and several manuals to reduce the risk of black start generators being offline due to fuel unavailability. The joint PJM, Brookfield Renewable and D.C. Office of the People’s Counsel package received 94% support in the sector-weighted vote.
The proposal, which is set to go before the Members Committee next month, creates a new category of “fuel assured” generators and requires at least one such unit in each transmission zone. The criteria to qualify as a fuel assured unit vary based on the resource type, including connections to multiple interstate gas pipelines, on-site fuel storage and dual-fuel capability.
PJM Senior Engineer Dan Bennett said the effort will create a methodological approach to looking at black start reliability. “We want to make sure this service is compensated fairly and recognized for what it brings to the grid,” Bennett said.
Black start resources whose unavailability during a blackout would cause the projected zonal restoration times to increase by 10 hours or more were identified as “high impact” sites with possible mitigation strategies laid out. The proposal calls for $28,175,000 in additional black start annual revenue for mitigation of the high-impact sites.
Calpine’s David “Scarp” Scarpignato said the requirement of one fuel-assured BSR per transmission zone may be insufficient, raising the possibility of a generator being offline or damaged during a blackout. He also noted that having penalties for fuel assured resources which fail to meet the requirements, but none for non-assured generators could discourage participation in the higher tier.
Joe Bowring, president of Independent Market Monitor Monitoring Analytics, said the proposal could result in overpayments as some BSRs which would qualify as fuel assured elect not to seek that designation, forcing PJM to enroll an additional fuel assured generator. He has also questioned the value of having non-assured resources such as intermittent generators providing black start.
Monitoring Analytics’ own package, which would have prohibited intermittent resources other than run-of-river hydro from enrolling as BSRs, did not receive the support of the Operating Committee and Market Implementation Committee. Bowring did, however, thank PJM for incorporating some of his suggestions into the joint package and said that overall it’s a proposal that provides a needed solution.
Stakeholders Narrowly Reject Demand Response Problem Statement and Issue Charge
The MRC narrowly rejected an initiative to consider the use of statistical sampling for interval-metered residential customer participation as demand response in wholesale markets. The problem statement received 48% sector-weighted support, just shy of the 50% required. (See “Stakeholders Endorse Prohibiting Gas Infrastructure Participation in DR,” PJM Market Implementation Committee Briefs: Oct. 6.)
CPower’s Ken Schisler said the requirement that curtailment service providers use customer meter data for measurement and verification is “an unreasonable barrier for residential metering.” Obtaining access to the data from electric distribution companies remains a challenge and once that data is received, Schisler said CSPs must manage hundreds of thousands of data points when calculating winter peak load.
He also raised the possibility of security issues related to holding large volumes of residential electric usage data, saying that privacy concerns could be greater for personal versus industrial data.
Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said the proposal offered an opportunity to receive information about barriers to the usage of smart meter data and noted that the adoption of a problem statement would not necessitate the adoption of any solutions examined.
The electric distributor sector had the strongest opposition to the proposal, joined by transmission and generator owners. End use customers unanimously supported the proposal and other suppliers had mixed support.
Alex Stern, of Public Service Electric and Gas, told RTO Insider he believes the MRC was right to oppose PJM becoming involved in residential demand response, which he believes should be addressed by state legislators and regulators before the RTO examines its own rules.
“We really need to respect the states and consider the policy issues, including but not limited to privacy — respecting the privacy of customers, as well as the … rights and responsibilities of states versus PJM,” he said.
Bowring also told the MRC that he believes access to meter data is a state policy issue and said he worries that PJM allowing statistical sampling as a workaround to issues in obtaining that data would create a disincentive for states and CSPs to find a more direct solution.
Paul Sotkiewicz of E-Cubed Policy Associates said the usage of statistical sampling could introduce inaccuracies in the markets and questioned why metering for demand response should be treated any differently from the requirements that generators are held to. “It opens up a can of worms we shouldn’t even be talking about.”
Support for Circuit Breaker Remains Mixed
Stakeholders remained divided on several proposals to impose a circuit breaker to limit the price and duration of high energy prices. None of the seven packages produced by the Energy Price Formation Senior Task Force received 50% support over the status quo in two task force polls, with a proposal from Calpine receiving the highest at 34%.
Presenting the joint stakeholder package, which received 14% support in the polls, Adrien Ford of Old Dominion Electric Cooperative said price spikes can be helpful to encourage generators to respond to issues the grid is facing. However, sustained high prices can result in load paying for tens of millions in higher rates every day that prices remain elevated and a risk of cascading market defaults.
Under the joint package, the circuit breaker would be triggered if the average LMP was above $1,000 for a rolling 24-hour period or above $850 for a rolling 168-hour interval. PJM would also be permitted to trigger a circuit breaker response but could not block one under the proposal.
The circuit breaker would remain in effect until the price cap had not been reached for five consecutive business days.
The proposal would also include administrative adders to provide cost recovery if the cost to generate power exceeds the circuit breaker price cap. Ford said the current rules require generators to go before FERC to seek cost recovery; the joint stakeholder language would shift the decision to PJM instead.
Bowring said that a circuit breaker should not suppress the market price below fundamentals like the cost of gas. Nor should it artificially increase prices by including any administrative adders, like Operating Reserve Demand Curve penalties or transmission constraint penalty factors, he said.
The Calpine proposal would cap the energy component of the LMP at $2,000 when the circuit breaker is triggered; generators would be paid uplift if the LMP is too low to cover their costs. The trigger would be 90 hours of non-consecutive shortage events since June 1, followed by any subsequent event during that delivery year lasting three or more hours. The circuit breaker would continue until the shortage event has ended.
Scarpignato said the $850 price cap under the joint stakeholder proposal would likely be below the cost of gas during many emergencies, while Ford said allowing prices to go as high as the $5,700 per MWh — which is the highest they can go under cost-based offers, reserve shortages and a $2,000/MWh transmission constraint penalty factor — would result in $61 billion in energy costs for a typical winter load or nearly $40 billion without the TCPF.
Jason Barker of Constellation and Sotkiewicz both said they could not support any of the current proposals and urged further discussion to find a compromise package. The MRC is scheduled to consider endorsing a package at its next meeting.
The MRC reviewed a proposal to provide PJM with added flexibility to modify the transmission constraint penalty factor when transmission upgrades are already underway. The PJM proposal aims to provide a solution to an issue identified in 2020, after one of just three transmission lines into Virginia’s Northern Neck peninsula was put on outage for a planned upgrade.
The outage caused price fluctuations that pushed the TCPF to its default of $2,000/MWh in the real-time energy market. Since the completion of the upgrades would resolve the issue and it wouldn’t be possible for new generation to be added prior to the work being finished, PJM successfully argued to FERC that the design of the penalty factor created “unjust and unreasonable energy market rates” for consumers. (See FERC Approves Pause of PJM Tx Constraint Penalty Factor in Va.)
Bowring argued that while PJM’s filing proposal addressed a real issue, its proposal would allow the RTO to subjectively determine penalty factors and does not address why penalty factors are triggered so often. Bowring said the penalty factors increased average PJM prices 11.2% in the first half of 2021 and 6.1% in the first half of 2022. Bowring stated that PJM reduces transmission line ratings by 5% and triggers these transmission constraint penalty factors unnecessarily.
A second IMM proposal failed to garner significant support over the PJM package and the status quo in an EPFSTF poll. The IMM’s alternative would broaden the trigger criteria and use a different methodology for the circuit breaker.
The PJM proposal is scheduled to be considered for endorsement by the MRC at its next meeting.
Two Proposals Remain on Variable Operations and Maintenance Costs
The MRC continued discussion of two competing packages to streamline the accounting of variable operations and maintenance costs.
The PJM proposalwould create default adders for minor maintenance and operating costs as an alternative to generators submitting unit-specific information and would provide definitions of major maintenance and minor maintenance for more clarity on which costs fall into each.
The Constellation package mirrors the PJM language with the exception of removing the refueling and associated maintenance from variable costs, with Barker saying those expenses should be considered part of the unit’s capacity offer, rather than its cost-based energy offer. He said such operations are “fixed” costs that don’t vary with run time.
“Defining planned outage costs as a component of VOM will require a significant annual VOM accounting for all nuclear units; akin to developing an ACR for each unit each year,” Constellation’s presentation said.
The Market Implementation Committee endorsed the PJM package with 70% support at its Sept. 7 meeting, with Constellation’s advancing as an alternative with 54% support. (See “Two Alternatives on VOM Advance to MRC,” PJM Market Implementation Committee Briefs: Sept. 7, 2022.)
Stern said PSEG supports Constellation’s language because it aligns with efforts to preserve nuclear power as a zero emission resource.
Bowring and Sotkiewicz, however, said the package would create a special carveout for one type of generation, with the latter asking if Barker would support an amendment to include time-based operations from other resource types. Barker said such a change would be too major for him to accept as a friendly amendment and would require additional stakeholder input.
Reworked Language on Critical Gas Infrastructure Participation in Demand Response Presented
PJM gave an overview of changes made to the language of a slate of Operating Agreement, Reliability Assurance Agreement and manual revisions to prohibit critical gas infrastructure from participating in demand response programs. Following MIC feedback that the definition of the infrastructure to be affected could be vague, staff removed the word “significantly” from the phrase “which if curtailed, will significantly impact the delivery of natural gas to bulk-power system natural gas-fired generation. (See “Stakeholders Endorse Prohibiting Gas Infrastructure Participation in DR,” PJM Market Implementation Committee Briefs: Oct. 6.)
The timeline for scheduling of future votes on the package has also been changed, with a vote at the Members Committee moved to December to avoid having the MRC and MC voting on the measure on the same day.
SPP’s effort to improve its congestion-hedging processes appears to be gaining traction with its stakeholders, thanks to a recommended hybrid approach that first focuses on equitably allocating congestion rights instruments and then increases the pool of awards available.
Staff presented its proposal to SPP’s Markets and Operations Policy Committee Oct. 11 and then again last week during the RTO’s quarterly joint stakeholder briefing, which stretched over two days. They were expected to bring a final recommendation to the board but asked that a vote be delayed until the directors meet again in January. (See SPP Markets and Operations Policy Committee Briefs: Oct. 10-11, 2022.)
In setting the stage for Day 2 of the discussion, COO Lanny Nickell used a mixed metaphor to explain staff’s two-part proposal to improve congestion hedges.
Nickell said that aligning the models will require five or six different changes on the process’ market-design side and then modifying transmission planning.
“I see those two things working together as one; we’re trying to create better balance, more equity on the market side and then increasing the amount of congestion hedges that might be available,” he said.
“Think about this as being a big pizza pie. Today, on the market side, you get one bite at the apple. We take the whole pie, we throw it out, the ravenous wolves all come charging in and they’d get as much as they can get, but there’s always somebody left hungry,” he said.
“Instead of throwing out the whole pie and letting the hungriest and the biggest do whatever they can to get as much as they can, let’s split that up into five different pieces. Let’s throw out a piece at a time. Everybody comes in and gets what they can, and you throw out the next piece, the theory being that by splitting things up into multiple pieces and giving people multiple chances, you’re more likely to have nobody left hungry. What we’re trying to do on the transmission side is increasing the size of the pie so that the pieces you throw out are even bigger than what they were before.”
“I understand this better. It’s not perfect, but I don’t know anyone that gets everything they want out of the [current] process,” Nebraska Public Power District CEO Tom Kent said.
“I think the staff has come up with a pretty unique and creative solution to the problem,” American Electric Power’s Richard Ross said. As chair of the Market Working Group, Ross has overseen several years of stakeholder efforts to address the situation.
“I think AEP is probably going to be close to neutral as an overall portfolio,” he said, “but the important thing is this aligns the congestion instrument with the congestion cost so that folks can see things and secure things directly rather than having to rely on the slush bucket at the end to hope they get fulfilled. This is doing something different … and it’s a pretty creative idea.”
If handled properly, Ross said, the improved process will help wind-rich utilities export their excess power out of the region, a recurring topic over the past few years.
EDP Renewables’ David Mindham said his company has struggled to gain auction revenue rights. He said congestion costs of $70/MWh have hampered wind developers’ ability to send power eastward to other regions.
“To put [it] in perspective, the cost of exporting that energy is two to three times the levelized cost of actually selling that generation to an entity outside of SPP,” Mindham said. “There’s no hedge for us. I think I can speak for the [wind energy] industry when I say none of us are even considering another export deal until this is fixed. It’s just it’s way too expensive.”
“What [staff] has advanced is a fairly comprehensive and solid concept in terms of moving forward,” Board of Directors Chair Larry Altenbaumer said. “We still need to work through the stakeholder process. This is not a final product here. There’s work to be done, but I do believe from my standpoint that it is responsive to the path forward that I was looking for anyway.”
JTIQ Studies to Replace AFS Studies?
Antoine Lucas, SPP’s vice president of engineering, said staff’s work with MISO to unclog interconnection queues and facilitate transmission along the RTOs’ seam could replace SPP’s affected system study (AFS) process.
The studies are conducted to determine whether generators seeking to interconnect in one RTO require transmission upgrades on the other side of the seam.
Lucas said the joint targeted interconnection queue study benefits will improve cost certainty for the RTOs’ generator interconnection requests, provide interconnection customers with AFS costs before cluster studies, and eliminate unknown AFS network upgrades and AFS study costs.
“We’re looking to use this process as a springboard into replacing the affected system studies. This aligns with where the industry is heading and also optimizes upgrades along the seam,” he said. “Rather than a [generator interconnection] customer identifying the interconnection and then upgrades made from bottom up, we would step back and look at an optimal set of projects.”
RSC Membership Turnover
The Regional State Committee honored several departing members during its Oct. 24 business meeting, including its longest-serving state regulator, Oklahoma Corporation Commission Chair Dana Murphy. A former RSC president, Murphy has been on the committee since 2011.
Incoming RSC president Andrew French, KCC | SPP
“Eleven years of time — you just blink your eyes and then it’s gone,” Murphy said. She will be replaced by the OCC’s Todd Hiett.
Jefferson Byrd, who is running for land commissioner in New Mexico, is also stepping down. Ted Thomas previously stepped away after resigning from the Arkansas commission. (See Arkansas PSC’s Thomas Makes Way for His Successor.)
The RSC also approved its Nomination Committee’s choices for next year’s officers. Kansas’ Andrew French will succeed Randel Christmann as president, with Iowa’s Geri Huser serving as vice president and Texas’ Will McAdams as secretary and treasurer.
In other actions, the committee approved:
RR497, which installs as a business practice the Project Cost Working Group’s oversight for applicable transmission projects that are funded through direct assignment of cost;
RR499, which adds new language to the planning criteria concerning terminology and their definitions, new capability and new operational testing requirements, out-of-season capability testing, capability and operational testing for new or upgraded units, and accreditation for thermal and hydro units;
RR508, which allows load-responsible entities to use deliverable capacity in meeting their winter season obligation;
RR516, which codifies the increase in SPP’s planning reserve margin from 12% to 15%.
The RSC also approved a clean audit of its 2021 financial statements.
SLC Pancaking Strawman Still in Flux
Murphy, who leads the RSC’s representation on the Seams Liaison Committee, a joint group with the Organization of MISO States to develop coordinated seams policies, reviewed with the committee an SLC working group’s proposed strawman for rate pancaking.
The Rate Pancaking Working Group in August listed several recommendations for treatment of unreserved use charges and emergency ties on the RTOs’ seams, improving the ability to obtain congestion hedges for procuring firm transmission, eliminating or reducing rate pancaking for long-term contracts, and eliminating interregional projects could cause unintended rate pancaking issues from interregional projects. (See MISO, SPP Regulators Finish Pancaking Strawman.)
Murphy said her SLC co-chair, Missouri’s Ryan Silvey, updated the OMS in September and requested feedback from the commissioners. She said he had not received that input when she last talked with him in October.
FERC Chair Richard Glick made his first in-person visit to SPP’s Arkansas headquarters last week, joining the grid operator’s stakeholders for their regular quarterly governance meeting.
The trip wasn’t Glick’s first to Arkansas. He served as former U.S. Sen. Dale Bumpers’ (D-Arkansas) legislative director and chief counsel for seven years, which brought him to The Natural State several times.
“The first question I would always get was, ‘You’re not from here, are you?’” Glick, a son of the North, said during the meeting.
He watched from the sidelines as the Board of Directors and the Regional State Committee, comprised of SPP’s state regulators, conducted their business in meetings that were closed to non-rostered members. Glick came away impressed with the RSC’s deliberations on resource adequacy.
“It was a real education because there’s a lot of other regions that have different approaches to state input and state stakeholder processes, and this is definitely unique,” he said. Nodding to SPP’s expanding Western market services, Glick added, “I can see why that’s attractive to others … especially in the West.”
Glick said SPP’s approach to state regulatory input will play a role as the RTO competes with CAISO to offer market services in the Western Interconnection.
“I’m pretty sure everyone would probably agree that eventually, there’s going to be at least one if not more than one RTO developed in the West. It’s certainly moving in that direction, and you all are playing a significant role,” he told stakeholders. “I think just providing an alternative to the California ISO, a structure which is obviously hobbled by the way that the ISO deals with independence or doesn’t have independence in terms of [its] board relationship. I think … the Regional State Committee approach is something that’s very attractive to a lot of the state regulators.”
Glick stressed the importance of accrediting generating resources’ capacity — and not just that of intermittent resources — to maintain grid reliability. He noted that in recent years “more traditional generating plants” have shut down when they should have been available, mostly because of extreme weather.
“It’s something that everyone needs to think about and be much more precise in how we define and accredit capacity,” he said.
Glick said FERC has devoted two years of technical conferences and internal discussions about the best way to structure markets going forward, given the challenges of ensuring reliability and the transition to clean energy.
“One of the questions is [whether] the markets are currently operating in a way that really achieves or maximizes the benefits associated with the transition,” he said. “We’ve had discussions about capacity markets, about ancillary services, about energy markets and other market reforms as well, and the one recurring theme that comes up in all of them is flexibility, the need for more flexibility as we go forward. It can be flexible natural gas; it can be storage; it could be other technologies as well.
“When I first came to FERC … at the beginning of the Trump administration, there was a lot of discussion about, ‘We need more baseload generation, we need to subsidize baseload generation,” Glick said. “To me, that’s the debate that’s kind of not really relevant for today. Today, the relevance to me is how do we incentivize flexibility? I don’t anticipate the commission coming up with anything in the near future on that issue, but it’s something I think we still think about and wanted to move on at some point in the future.”
$245M Operating Budget Approved
The board approved SPP’s 2023 operating budget, net revenue requirement and capital budget following unanimous endorsement by the Members Committee.
The $245.6 million budget is a 6.2% increase over the current year — about two-thirds less than last year’s 17.7% — with salaries and benefits representing the largest share of growth. SPP instituted a one-time, across-the-board raise for staff this year to compensate for inflation.
American Electric Power’s Richard Ross raised concerns that SPP is “too ambitious with our activities that are not a part of our core functions.” Ross often refers to those functions as the grid operator’s “food and shelter” responsibility.
“I’m concerned that we are too ambitious with our activities that are not part of our core functions, in particular, the Western expansion,” he said, citing “recent studies” that indicate the current footprint will see “minimal” benefits from the effort. “I think we need to strongly evaluate whether or not we need to continue the major push that we’re under and whether or not that is truly in the best interest of the core functions of SPP in the long-term.”
“It’s definitely a known item, and there is focus on how that is going to get addressed, because resourcing is critical,” CEO Barbara Sugg responded.
She said SPP has onboarded 81 new staffers this year, but that the turnover rate remains high. She said leadership is taking steps to recruit the “best and the brightest, but also to increase retention.”
The net revenue requirement (NRR) will rise 4.7%, from $176.3 million to $184, Finance Committee Chair Susan Certoma said. SPP’s tariff limits the NRR to a ratio of estimated annual transmission usage, capped at $0.465/MWh. That rate has been set at $0.448/MWh for 2023 but is projected to peak at $0.494/MWh in 2025 before decreasing.
CFO Dunn Retires
Directors and members honored SPP CFO Tom Dunn, who is retiring after 21 years on Dec. 2.
“So, there’s still plenty of time to harass him,” Sugg said.
She said SPP’s headcount increased by 500 employees and its operating budget by $175 million under Dunn’s leadership, and he secured more than $400 million in financing to fund the RTO’s growth while maintaining the lowest cost of service by any system operator.
“Tom has been an invaluable resource to me as well as to all of SPP. I’m thrilled that Tom hung in there with me as the new CEO,” Sugg said. “He has taught me so much about his area of responsibility, but he’s also such an asset to the executive team … who can present different alternatives and suggestions and just kind of help us think out of the box a little bit, which I think is a tremendous asset for all of our executives.”
At first reluctant to speak after the board’s resolution, Dunn recalled one of his first staff meetings. Former CEO Nick Brown asked him to explain finance to the employees. Dunn complied.
“I spent 30 minutes, and [Brown] never invited me to do it again,” he said. “I enjoyed my time at SPP. It’s the best career move I’ve ever made.”
Membership Elects 2 New Directors
The RTO’s membership elected two new directors and one incumbent to the board during SPP’s Annual Meeting of Members.
Joining the board are former ISO-NE general counsel Ray Hepper and Steve Wright, a former Bonneville Power Administration CEO and general manager of Washington’s Chelan County Public Utility District. Bronwen Bastone was elected to a second three-year term.
Wright’s term is effective immediately, as he replaces long-time director Julian Brix, who recently retired from the board. He gives SPP a second director with experience in the Western Interconnection in addition to John Cupparo, which could come in handy as the RTO expands its Western services.
Board chair Larry Altenbaumer reads a resolution honoring six-year director Mark Crisson (right). | SPP
Wright said in a press release that he hopes to “strengthen the bridge” to SPP’s potential Western members. “SPP is at the center of our nation’s ambitious efforts to attain a reliable, affordable and clean electric power system,” he said.
Hepper’s term will begin Jan. 1. He was elected to ERCOT’s board in 2020 but only served a few weeks before the 2021 winter storm came within minutes of collapsing the Texas grid. After several days of outages, Texans directed their ire at the ISO’s out-of-state independent directors, who also resigned.
The SPP board will undergo several other changes next year. Current chair Larry Altenbaumer, who has been on the board since 2005 and has one year left on his term, will step aside in favor of Certoma. Elizabeth Moore will replace Certoma as vice chair.
Mark Crisson is also retiring after six years on the board. The board and members honored Crisson with a standing ovation and a resolution recognizing his service.
“I told Mark it’s been an honor for me to serve with someone like him. … He is perhaps one of the most quietly effective individuals you will encounter,” Altenbaumer said. “He is a very straightforward individual, and if he disagrees with you, he will very constructively let you know that he disagrees with you. I really value that in terms of his role as a board member and the guidance that he sometimes shared with me, even when it wasn’t guidance.”
The membership also elected six new members and six incumbents to the 22-person Members Committee.
Joining the committee for the first time are EDP Renewables’ David Mindham (Independent Power Producer/Marketer segment); Tri-State Generation and Transmission Association’s Mary Ann Zehr (Cooperative); Arkansas Electric Cooperative Corporation’s Buddy Hasten (Cooperative); Google Energy’s Will Conkling (Large Retail); American Clean Power Association’s Daniel Hall (Alternative Power/Public Interest); and Southwestern Public Service/Xcel Energy’s Adrian Rodriguez (Investor-owned Utility).
Re-elected to the committee are American Electric Power’s Peggy Simmons (Investor-owned Utility); Northwestern Energy’s Bleau LaFave (Investor-owned Utility); City Utilities of Springfield’s (Mo.) Chris Jones (Municipal); Dogwood Energy’s Rob Janssen (IPP/Marketer); ITC Great Plains’ Brett Leopold (Independent Transmission Company); and Basin Electric Power Cooperative’s Tom Christensen (Cooperative).
Board Approves 2022 ITP, Consent Agenda
The board approved staff’s 2022 Integrated Transmission Plan, a reliability-only portfolio. The 17-project, $35.4 million plan solves 25 system needs in rebuilding 11 miles of transmission but will not result in any new transmission.
Its unanimously approved consent agenda included chairs for the following stakeholder groups: Credit Practices Working Group, Caleb Head (Northeast Texas Electric Cooperative); System Protection & Control Advisory Group, Chris Angland (Omaha Public Power District); Project Cost Working Group, Brian Johnson (AEP); and Market Working Group, Richard Ross (AEP).
The agenda included the Corporate Governance Committee’s nominations for several committee assignments: Golden Spread Electric Cooperative’s Mike Wise to the Finance Committee; GridLiance High Plains’ Noman Williams to the Human Resources Committee; and AEP’s Ross, Basin Electric’s Christensen, NextEra Energy Resources’ Matt Pawlowski, and Golden Spread’s Natasha Henderson to the Strategic Planning Committee.
It also included several modified and withdrawn notifications to construct, an amended and restated Western Joint Dispatch Agreement to facilitate three Black Hills Corp. subsidiaries’ 2023 membership into the Western Energy Imbalance Service market, and six revision requests previously endorsed by MOPC:
RR499: Adds new language to the planning criteria concerning terminology and their definitions, new capability and new operational testing requirements, out-of-season capability testing, capability and operational testing for new or upgraded units, and accreditation for thermal and hydro units.
RR508: Allows LREs to use deliverable capacity to meet their winter season obligation.
RR512: Requires LREs to submit used and unused capacity on behind-the-meter resources that have qualified as accredited capacity that can be used to respond to emergency conditions.
RR514: Updates the operating constraint and spin violation relaxation limits by increasing the values of all operating reserve constraints not subject to market-to-market coordination to $1,500
RR516: Codifies the increase of the planning reserve margin from 12% to 15%.
RR520: Gives the balancing authority greater ability to forecast and measure non-registered, available demand response by analyzing data submitted daily from affected LREs.
The nuclear industry descended on D.C. last week to make the case for advanced reactors, both large and small, with some so small that they could be built at existing industrial sites to supply behind-the-meter dedicated power and heat.
On Monday, The Atlantic Council, working with the United States Nuclear Industry Council (USNIC), webcast an eight-hour live program featuring more than 30 speakers in a half-dozen discussion panels.f
And on Wednesday, the International Atomic Energy Agency began a three-day conference in D.C. focusing on the rebirth of nuclear energy in the U.S. and around the globe, in part as a reaction to Russia’s decision to cut natural gas exports to Europe and to address the plight of nearly 1 billion people globally who have no electricity, participants said. U.S Department of Energy leaders played prominent roles.
Once in a Lifetime Financial Boost from Federal Legislation
Beyond the situation created by Russia, which some participants at the events repeatedly called a “global energy crisis,” the passage of the Inflation Reduction Act (IRA) earlier this year as well as the Infrastructure Investment and Jobs Act (IIJA) in 2021 have galvanized U.S. nuclear proponents to look for ways to make nuclear power more competitive. It has also catapulted the reputation of the U.S. as a global leader in nuclear technologies.
The IRA will provide production tax credits to reactor owners, even to owners of existing reactors. The PTCs will be similar to what wind and solar have received for years. The zero-emission nuclear production tax credit provides up to $15/MWh — assuming labor and wage standards are met — from 2024 through 2032.
DOE in September stirred more interest in building advanced nuclear with the release of a study concluding that 157 sites of former coal-fired power plants would be suitable sites for nuclear plants. And because nuclear reactors are designed to run without interruption, giving them a high capacity factor, the nukes would not have to be as large as the original coal plants. The study also found that 237 operating coal plants could be considered for a nuclear replacement.
Existing nuclear plants are also getting new attention. The IIJA contained a provision that would create a $6 billion Civil Nuclear Credit Program, providing cash supplements to reactor owners who would otherwise be forced to shut down.
Awards have yet to be made but the first applications — totaling about $81 billion — are now under review.
8 Hours with the USNIC
The Atlantic Council’s multiple panel discussions began with a review of the renewed global interest in nuclear power, including interest from nations preferring to work with U.S companies and the U.S. government rather than state-owned enterprises connected to Russia or China.
The predominant focus was the rebirth of nuclear power as the best technology to address climate change while simultaneously providing national energy security.
“We have a renaissance in investment in the nuclear industry today, with record amounts of private capital being invested … about $4 billion last year,” said André Pienaar, CEO of C5 Capital, a venture capital firm with offices in London, Washington and Luxembourg.
C5 focuses on cybersecurity, space and nuclear energy. Investors are looking across “the whole spectrum of innovation, from small modular nuclear companies, all the way through to the promise of nuclear fusion,” Pienaar said.
The mention of fusion was a reference to U.S.-based developers of fusion reactors, which create energy by fusing helium atoms rather than splitting enriched uranium.
More immediately, Pienaar was referring to fission reactors of 300 MW and smaller, down to those as small as 50 MW, some using technology like the large traditional light water reactors now in commercial service, others designed around more exotic technologies with passive safety systems to make them “walk away safe.”
Small modular reactors (SMR) are factory-built, enabling the manufacturer to increase quality control while providing faster installation than traditional large reactors at a lower cost.
“The investments in SMRs are not limited to private capital,” Pienaar said, referring to NuScale Power (NYSE:SMR), an early developer of small modular reactor design. NuScale has been publicly traded since its merger last spring with Spring Valley Acquisition, a special purpose acquisition company created by banks, institutional funds and private investment groups.
“We’ve also seen significant cross-border investment. Constellation Energy invested in the Rolls Royce SMR consortium in the UK,” Pienaar said, adding that Cameco and Brookfield Renewable Partners this month purchased Westinghouse Electric in a deal valued at $7.87 billion.
Cameco (NYSE: CCJ) is a Canadian uranium mining company. Brookfield (NYSE: BEP) is a publicly traded limited partnership headquartered in Canada that owns hydroelectric, wind, solar and power storage facilities in North America as well as South America, Europe and Asia.
Westinghouse manufactures equipment for nuclear reactors operating around the globe and provides services to U.S. reactors as well.
Competition Among SMR Makers
At this point, NuScale appears to be ahead of competitors striving to market a working SMR.The Nuclear Regulatory Commission approved NuScale’s design in August, opening the door for the company to begin selling them rather than building demonstration projects.
Founded in 2007, NuScale designed a self-contained 77 MW pressurized water reactor. Up to 12 of these factory-built “modules” can then be configured in a “multi-module” container and operated from a single control room.
X-energy, a Maryland company that has designed a gas-cooled high temperature SMR, is aiming at providing reactors that the company says cannot meltdown to private industry in need of reliable power and on-site heat. The company’s basic reactor, the Xe-100, is rated at only 80 MW but can be “scaled” into a four-pack, 320-MW power plant. X-energy won a $1.1 billion matching grant through the IIJA.
Marcy Sanderson, a nuclear engineer and vice president at X-energy, said the reactor operates at a little over 1,000 degrees F. Today’s conventional reactors operate at roughly 550 degrees (boiling water reactors) to 600 degrees F (pressurized water reactors).
Rather than fuel rods as in conventional reactors, the Xe-100 uses “pebbles,” small balls of extra-enriched uranium., an arrangement that allows the reactor to “ramp” up and down, something conventional reactors are not good at doing.
“The inherent characteristic of our design is exceptionally well-suited to what we consider an … opportunity right now, trying to take meaningful, tangible steps to decarbonize heavy industry, support the carbon challenge, support the climate crisis that we all know is in front of us,” Sanderson said.
Because the fuel “has been hailed as the safest fuel on earth, we can talk about doing something like siting a nuclear power station next to a chemical facility,” she said.
The facility in question is owned by Dow Chemical.
Dow and X-energy have announced a preliminary agreement to install an Xe-100 at one of Dow’s Gulf Coast facilities to provide heat and power, said Kreshka Young, a Dow business director, in another panel.
“We’re looking for high-temperature, high-pressure steam to support our heat needs at our sites. And by high temperature I mean in pretty much all cases [temperatures] greater than 500 Celsius [932 F], and then it goes up from there.”
Young said Dow is also looking for reliability.
“For steam, we’re really relying on our on-site generation, whether that’s from a gas turbine, from a boiler, or in this case from a reactor. Whatever the source of that steam, it must be reliable,” she said.
“And when I mean reliability, I don’t mean the 95% reliability. When we say reliability for steam, we need 99.995% reliability,” she said. “We need a backup, and then maybe even a backup to a backup. The modularity of X-energy’s design … combined with the steam temperatures that it can reach made it one of the technologies we thought would be a really good fit for us.”
Dow additionally has emissions reductions goals, she said.
“We’ve already reduced our carbon emissions since 2005 by 15%. We have a goal to reduce them another 15% by the end of this decade, and to be net zero by 2050.”
From left: Kurt Scherer, managing partner, C5 Capital; Marcy Sanderson, X-energy; and Kreshka Young, Dow Chemical | Atlantic Council
Globally, the company currently produces about 7 GW equivalent of power and steam for use at its manufacturing sites, with any excess sold to the market. “That’s produced with over 50 gas turbines and gas-fired boilers. That energy production is about 50% to 55% of Dow’s total carbon emissions,” Young said.
Another SMR competitor is TerraPower, an engineering company founded in 2008 by Bill Gates specifically to design advanced nuclear reactors. Company CEO Marcia Burkey also argued in another panel discussion that investors have decided nuclear energy has a role to play.
“There is a growing recognition that nuclear power must be part of the mix. It’s a small footprint. It’s a very dense energy form. It certainly addresses energy independence, and that’s a growing concern and preoccupation, not just of providers [of generated power] but of investors.”
TerraPower is planning to build a 345-MW advanced reactor in partnership with GE Hitachi on the site of a Wyoming coal-fired power plant scheduled to shut down. The reactor will be cooled by liquid sodium rather than pressurized water as in traditional large commercial reactors, enabling it to run at lower pressures.
The reactor power plant will include a molten salt storage system, allowing operators to store the heat from the reactor core rather than use it immediately to make electricity as conventional reactors now do.
Burkey said her company has raised funds globally in anticipation of building small advanced reactors around the world. She said the company had recently spent time with potential investors in a drive to raise $750 million in new private capital.
“I would say that strategics [strategic industries]were very interested because they could see the potential to bring into their operations a carbon-free source that helps them meet their own goals, and [to] participate in the supply chain and help us to accomplish our goals. I would say private equity was very interested,” she added.
Another speaker also mentioned that the interest in small U.S.-designed reactors is international.
Rick Springman, senior vice president at SMR, a maker of SMRs and now a division of the privately held Holtec International Company, said overseas clients are interested in the company’s technology and are calling to ask whether Holtec can manufacture an SMR with a design that meets specific regulations in their countries. He said operating regulations should be at least “harmonized” as the demand for SMRs continues to grow.
“I think harmonization is a key and needs to be connected to financing. Because if you take a U.S. technology with the U.S. regulation and you go abroad and you change it, you’re going to end up with a different plant, period. If you apply different codes and standards you’re going to end up with a different plant.”
In another panel discussion, Rafal Kasprow, CEO of Orlen-Synthos Green Energy, a joint venture in Poland of Synthos Green Energy and PKN Orlen, the largest multi-energy company in central Europe, said his company is a good example of private capital and the international nuclear renaissance.
Earlier this month his company signed a master services agreement with Laurentis Energy Partners, a Canadian company with European operations, to build and deploy a fleet of SMRs designed by GE Hitachi. The small reactors are rated at 300 MW and designed with passive safety systems, making them less likely to suffer catastrophic failures. Kasprow said U.S.-designed nuclear technology is in high demand.
“I think that there’s a recognition now of the geopolitical risks associated with doing business with Russia or China,” Kasprow said, adding that demonstrating the economics of nuclear energy is no longer a problem.
“People are calling every day, from meat-packing companies, from chemical businesses and other businesses, asking ‘Do you have SMRs? Can you deliver? We will pay cash,’” he said.
Bridge to Bankability
Whatever the advantages that nuclear offers, the new SMR technology is competing with numerous other technologies, all hungry for investor — and tax — dollars in what has become a rush away from conventional fuels.
In a one-on-one interview with the Atlantic Council’s Landon Derentz, Jigar Shah, head of DOE’s Loan Program Office, provided a frank evaluation of the hectic activity his office now faces from U.S. companies and entrepreneurial groups competing for the billions of dollars in tax credits, production credits, loan guarantees and matching grants across a broad spectrum of energy technologies, including nuclear.
The function of the loan office, making loans to companies involved in promising technologies but risky market penetration is often described as building a “bridge to bankability” in the sense that if these companies can achieve full market acceptance they will qualify for conventional financial banking.
“We’re building a lot of bridges these days here in the United States. I think when you look at sectors that are actually at scale today, solar wind, EVs, lithium-ion battery storage, you’re looking at a minimum of $100 billion in private sector capital before they [can achieve] real market acceptance from the commercial banking sector,” Shah said.
“There are lots of technologies that are in different phases of getting support — hydrogen, carbon sequestration and storage, nuclear and others — that are coming to the Loan Programs Office,” Shah said. “There’s some rhyme or reason but not a lot. It’s not based on the readiness of technology.
“It’s based on who’s promoting the technology, who that CEO is and their ability to raise capital right in the marketplace, some of which comes from their previous roles and experience and some of which comes from who their sponsors are and where that support is coming from.”
“But how does that translate into brass tacks when industry wants to approach you?” Derentz asked. “What do you need from them to articulate that because each company is bringing its particular interest. Do you need a comprehensive view? Do you need a consortium view or viewpoint? What is the most helpful for approaching the loan office?”
Shah responded: “A supply chain investment doesn’t work unless they’re supplying something to somebody. Right? If they have one order for something, and then they come into the Loan Programs Office for a loan, I’m saying, ‘Who would you supply next? Who would be two, three and four?’
“I think nuclear is one of the hardest conversations because of this private sector-led, government-enabled approach that we have here in the U.S. The U.S. has a challenge around figuring out who goes first. And I do think that the Department of Energy can play, and is playing today, a critical role in facilitating those conversations.”
MISO’s 2022 transmission planning portfolio cleared its first vote before the Board of Directors, though some stakeholders have lodged complaints over the package.
During a teleconference Tuesday, the board’s System Planning Committee voted unanimously to send the $4.3 billion, 382-project 2022 Transmission Expansion Plan (MTEP 22) to a full board vote in early December.
MTEP 22 earned just four votes in favor of recommendation and five abstentions from MISO’s 11 stakeholder sectors. (See Stakeholders Endorse MISO’s Final MTEP 22.) The Transmission Developers sector voiced complaints over a lack of a meaningful project alternative process, while the Environmental sector said MTEP planning cycles need to incorporate more preparation for grid-enhancing technologies, increasingly common extreme weather events and advance notice when transmission owners’ age and condition projects are going to come due.
The Environmental sector also said it had concerns over MISO’s wording in MTEP 22 that carbon-reduction goals alone are driving the footprint’s resource transition and that gas generation can help navigate the changeover.
Vice President of System Planning Aubrey Johnson said the “vast majority” of projects to address age and condition of existing equipment — which represent the largest spending share of MTEP 22 — are not conducive to alternative project proposals. He said lower-voltage lines simply need replacement in many cases.
Johnson said MISO believes it has a comprehensive and transparent planning process and that he didn’t notice members taking exception to any projects in particular. He said MISO’s separate long-range transmission planning process resolves many of the Environmental sector’s concerns over MTEP being too shortsighted.
Some members have asked if the vote tally was concerning to MISO and whether the RTO needs to reassess this year’s transmission spending package.
“I think the vote indicates that many feel that there’s still a need to improve the MTEP report,” Clean Grid Alliance’s Natalie McIntire told board members. She said MISO should remove MTEP 22’s references to natural gas generation being able to provide a reliable backstop to renewable generation’s output and that the RTO needs to keep with its practice of being resource agnostic.
But Prairie Power’s Karl Kohlrus said MISO hasn’t adequately factored in its planning how removal of all Illinois’ fossil generation by 2045 under the state’s Climate and Equitable Jobs Act will affect system reliability.
“MISO is heading for a major train wreck,” he warned.
Kohlrus has previously said during planning meetings that he was concerned that the RTO isn’t reflecting enough future baseload retirements in its 20-year models used for transmission planning.
Johnson said stakeholders’ comments are expected, given the accelerating resource shift.
MISO Director Nancy Lange said MISO’s review of age and condition projects should consider “factors that all these regions are grappling with.”
Johnson said transmission projects related to age and condition and load growth provide the foundation for long-range transmission planning to accommodate the resource transition. He said there’s “a lot of connective tissue” between MTEP and long-range transmission planning.
“We’re in a state of transition right now. It’s taking a tremendous amount of effort from all parties to do this foundational work,” he said.
“It’s not surprising that we’re having a lot of differences of opinion,” MISO Director Phyllis Currie said, adding that the board and MISO take stakeholders’ concerns seriously.
During an Advisory Committee teleconference Oct. 26, the Union of Concerned Scientists’ Sam Gomberg asked if MISO was weighing whether to open an inquiry into MTEP 22’s scant support to avoid conflict with approving the transmission package later this year.
“It’s certainly something that raised my eyebrows, personally,” Planning Advisory Committee Chair Cynthia Crane said.
WEC Energy Group’s Chris Plante also said he thought the voting results were “concerning.”
MISO Senior Director of Transmission Planning Laura Rauch said the comments explaining why some MISO sectors withheld support of the plan are “helpful.”
Rauch said the vote “did not mean stakeholders weren’t active and engaged” in this year’s planning process. She said MISO looks for ways to continually improve the MTEP process.
ERCOT stakeholders have submitted comments on proposed amendments to the grid operator’s bylaws that have been sitting with the Board of Directors since September.
The amendments, drafted by staff at the board’s direction, would no longer require members’ approval of such changes. It would require that members be provided notice and the chance to comment on any proposed amendments or other “fundamental actions.”
Members had until Sept. 30 to comment on the revisions. The board was to discuss the amendments during its October meeting but did not do so in a public forum.
Jupiter Power’s Caitlin Smith filed comments on behalf of 26 other members, saying it is “imperative to emphasize the chilling effect the proposed amendments could have on decisions to enhance and maintain the health and reliability of the ERCOT grid, including continued investment in generation.”
“A successful energy-only market requires that its participants have a vested interest in the activities of the organization,” Smith said, referring to the development and refinement of market policy and rules.
“Corporate members must vote to amend the ERCOT bylaws,” she said. “Eliminating this right of ERCOT stakeholders is a clear signal to investors of regulatory and market uncertainty, which sends a negative investment signal that, all else equal, will impact operations, reliability and the provision of energy to consumers within the state.”
Smith said that if the proposed amendments are adopted, ERCOT’s governance structure will “most closely resemble” CAISO’s.
ERCOT Assistant General Counsel Jonathan Levine was unable to clarify the board’s next steps on the amendments during the Technical Advisory Committee’s short, virtual meeting Oct. 26.
“It’s a pretty fluid situation at this point. It’s up to the board and the board chair of what they want to do,” he said. “I apologize for not having any better information about where we’re heading on the bylaws amendment. I’m just a mouthpiece here.”
The Protocol Revision Subcommittee said it is working on a priority revision process that TAC shared with the board’s Reliability and Markets Committee in October. A draft will be presented during TAC’s Dec. 5 meeting. (See “TAC Shares Changes with R&M,” ERCOT Board of Directors Briefs: Oct. 18, 2022.)
Combo Ballot Approves TAC’s Annual Review
TAC’s combination ballot last week included the results of its annual structural and procedural review, two nodal protocol revision requests (NPRRs), a revision to the Load Profiling Guide (LPGRR), an other binding document request (OBDRR) and a change to the Retail Market Guide:
NPRR1128: would set a 1-cent/MW lower ancillary service (AS) offer floor for fast frequency response (FFR) responsive reserve (RRS), thereby allowing, depending on relative AS offers, FFR procurement up to the current limit without proration with other RRS categories in the ancillary procurement process.
NPRR1148: would resolve protocol gaps found during emergency contingency reserve service’s creation of its system change requirements.
LPGRR069: would add Lubbock Power & Light’s service address zip codes to the guide and updates the ERCOT service territory map to include Lubbock County. The LPRR also corrects zip code counts that were omitted in the count column.
OBDRR043: would align the operating reserve demand curve’s methodology with NPRR1148.
RMGRR170: would define the inadvertent gain/loss (IAG) process and an IAG; clarify its appropriate use; and clarify the IAG process’ appropriate use.
Public Service Enterprise Group (NYSE:PEG) is mulling whether to remain a 25% partner with Ørsted in the Danish developer’s Ocean Wind 1 project in New Jersey, CEO Ralph LaRossa said Monday as he laid out the company’s future clean energy plans in its third-quarter earnings call.
The company acquired the share shortly after the New Jersey Board of Public Utilities (BPU) in 2019 picked Ørsted’s 1,100-MW project to be the state’s first offshore wind project. LaRossa spoke in his first earnings call since he took over from his predecessor, Ralph Izzo, on Sept. 1.
“We are approaching a final investment decision [FID] on Ocean Wind 1 in New Jersey to determine if we will proceed to the construction phase,” LaRossa said. “We are reviewing our options related to our 25% equity investment as well as our option to purchase” 50% of Ørsted’s Skipjack Wind 2 project in Maryland, he added.
On Ocean Wind, “one of the things we’re looking at there is where the costs come in, and what that project looks like from an investment standpoint,” he said. Also part of the consideration are changes in revenue and expenses, he said. Under questioning from investment analysts, CFO Dan Cregg said there is no date stipulated in the contract for the decision.
An “FID moves you to the construction phase of the project, and so it’s when things are ready to move to that phase,” he said. Company officials gave no indication as to whether they would withdraw from the joint venture or remain as a partner.
Offshore Transmission Opportunity
LaRossa said that despite the fact that the BPU last week awarded PSEG only a small part of the work to upgrade the state’s transmission system in preparation to handle energy from the offshore wind projects, the utility believes that it could still get a substantial share of future work.
The BPU on Wednesday voted unanimously to spend $1.07 billion on transmission upgrades to deliver 6,400 MW of offshore wind generation to the PJM grid, saying the projects would minimize costs, environmental impacts and permitting risks (QO20100630). The BPU made its selection from among 80 proposals submitted by 13 developers in response to a solicitation issued by PJM at the BPU’s request under FERC Order 1000’s State Agreement Approach. (See related story, NJ BPU OKs $1.07B OSW Transmission Expansion.)
Among the submissions for the solicitation were proposals by PSEG individually and the Coastal Wind Link, submitted with Ørsted, which would use an offshore mesh system to transmit electricity onshore. Rizzo in May said PSEG could potentially secure projects costing $3 billion under the solicitation, although he also acknowledged the company may also get nothing. (See PSEG Sees Potential $3B OSW Transmission Spending.) LaRossa said that based on the contracts awarded last week, the offshore work potentially available to the PSEG-Ørsted partnership could be between $2 billion and $7 billion.
“We remain optimistic that our emphasis on reliability and resiliency will keep it as a strong contender for any future offshore transmission solicitations to bring regional offshore wind projects onshore,” he said. If the company did pull out of the Ocean Wind 1 project, it potentially could invest more in transmission systems linking the offshore projects, he said, noting that the BPU solicitation sought transmission proposals only for the state’s goal (at the time) of 7.5 GW of offshore wind power by 2035. New Jersey Gov. Phil Murphy on Sept. 21 announced that he had increased the state’s offshore wind target to 11 GW by 2040.
“We’re still hopeful on that offshore transmission and a full mesh network,” LaRossa said. “We think our mesh network is absolutely the most resilient and most robust.”
Nuclear Tax Credits
LaRossa said that the company also expects to benefit from the Inflation Reduction Act, which he said would have “important revenue visibility and price-stabilizing benefits” for the utility’s 3,770-MW nuclear fleet. The act, which was signed by President Biden on Aug. 16, provides production tax credits of up to $15/MWh for certain nuclear plants, from 2024 through 2032.
The credits will “will extend the visibility and stability of cash flows into the next decade,” LaRossa said in an earnings release. “These incentives will lower customer costs over time and support the continued operation of existing nuclear plants — which are New Jersey’s largest carbon-free base load energy resource.”
PSEG reported net income of $114 million ($0.22/share) in the third quarter, compared to a net loss of $1.564 billion ($3.10/share) a year earlier. The 2021 loss was from an impairment charge from the sale of the utility’s fossil assets.
Non-GAAP operating earnings for the third quarter of 2022 were $429 million ($0.86/share) compared to non-GAAP operating earnings of $495 million ($0.98/share) in the third quarter of 2021.
National Grid USA must pay $512,000 in penalties to the Northeast Power Coordinating Council (NPCC) for violations of NERC reliability standards, under a settlement approved by FERC on Friday (NP22-33).
According to the agreement, National Grid — which owns about 8,900 miles of transmission lines and 387 substations and serves about 3 million customers in New York and Massachusetts — admitted to three separate violations. Two involved FAC-008-3 (Facility ratings), and the third PRC-023-4 (Transmission relay loadability). All were self-reported.
At issue with the FAC-008-3 violations were requirements R6 and R8 of the standard. R6 requires that each transmission and generation owner have facility ratings for their solely- and jointly-owned facilities that are “consistent with the associated facility ratings methodology” (FRM), while R8 specifies the information that TOs must provide to reliability coordinators and other stakeholders when requested.
National Grid first realized that it might be in violation of the standard while it was preparing for its annual TPL-001-4 planning assessment and “another related project” in September 2019. Specifically, the entity discovered that “six transmission facilities did not have facility ratings … that were consistent with its” FRM. A subsequent extent of condition review, in which National Grid analyzed the facility ratings for all of its 726 bulk electric system elements in New England and New York, revealed similar issues at 100 facilities.
That was not the last time the utility would unearth ratings discrepancies at its facilities. During an asset baseline pilot in 2021 during which National Grid conducted field visits to 20 substations to verify field conditions, the entity found eight more facilities in which the field conditions did not match the ratings on record (another eight had already been flagged during the earlier review).
National Grid determined that the incorrect ratings had begun “on a variety of different dates,” stretching back to 2007 or earlier. NPCC asserted that because of the long duration, multiple versions of the standard were violated, from FAC-009-1, which took effect June 2007, to FAC-008-4, the currently effective standard.
The violations of R8 were discovered during the same planning assessment in 2019, with National Grid reporting to NPCC that it had failed to provide ISO-NE and NYISO accurate facility ratings for six transmission facilities. An extent of condition review found similar discrepancies at 154 facilities, later determined to span a similar time frame as the R6 violations.
NPCC assessed both the R6 and the R8 violations as a serious risk to bulk power system reliability, noting that incorrect facility ratings cause system operators to operate “with a decreased level of situational awareness in real-time and [monitor] contingencies with reduced accuracy.” Mitigation actions are ongoing and not expected to finish until 2025. They include walkdowns of all 175 BES substations and switching stations in New York and New England, with visual inspections of nameplates, transformers and bus conductor types at each station.
National Grid has already updated facility ratings with NYISO and ISO-NE where possible and updated its FRM “to document how global changes to key assumptions will be implemented and/or applied to existing facility ratings.” It has also begun a semi-annual review in New York “to verify that facility ratings updates made within the previous six months were correctly implemented and documented.”
Relay Setting Slip-ups
The utility’s violation of PRC-023-4 involves requirement R1, which details the criteria that TOs, GOs and distribution providers must use on circuit terminals to “prevent [their] phase protective relay settings from limiting transmission system loadability.” Criterion 1 tells utilities to set relays “so they do not operate at or below 150% of the highest seasonal facility rating of a circuit,” while criterion 2 requires relays to be set “so they do not operate at or below 115% of the highest seasonal 15-minute facility rating of a circuit.”
National Grid notified NPCC in July 2019 that it was noncompliant with R1 because 10 of its protective relay settings did not meet criterion 1 for relay loadability. The following year the utility reported an additional relay setting that did not meet criterion 2, and it reported five more violations of criterion 1 in 2021. In all, there were 16 noncompliant relay settings affecting 13 transmission lines. The infringements began in 2010 and had all been corrected by September 2021.
NPCC determined that the violation posed a moderate risk to BPS reliability: While improper protective relay settings increase “the risk that transmission lines would trip prematurely,” the RE also noted that National Grid is a summer peaking system and the feeder loadability issue affects the winter season.
National Grid’s mitigation actions include applying new settings for appropriate relays and implementing a tracking spreadsheet to ensure PRC-023 compliance among applicable relays. The utility also implemented a new training module for the protection engineering team on completing the new spreadsheet, and committed to update the annual training — next scheduled for January 2023 — to “include the different calculations that exist and when to apply them.”
New England’s largest utility is piling on to calls for winter help from the federal government.
In a letter to President Biden last week, Eversource Energy (NYSE:ES) CEO Joseph Nolan asked the administration to start preparing for possible emergency action as New England stares down what could be a dicey winter for the region’s electric grid.
“As both an energy company CEO and a lifelong New Englander, I am deeply concerned about the potentially severe impact a winter energy shortfall would have on the people and businesses of this region,” Nolan wrote.
He laid out a problem that has become familiar to energy policymakers in the Northeast: pipeline constraints, a lack of fuel storage capability and a volatile LNG market, which together could mean rolling blackouts if the region sees a period of extreme, extended cold.
Nolan pointed to four possible emergency actions that the federal government could take:
a waiver of the Jones Act to make it easier for imported LNG to get to terminals in New England;
an emergency order under Federal Power Act Section 202c, which allows the secretary of energy to order “temporary connections of facilities and such generation, delivery, interchange or transmission of electric energy”;
an emergency order under the Natural Gas Policy Act, which addresses a “severe natural gas shortage”; and
using the Defense Production Act to prioritize domestic energy supplies.
Waiting until an emergency arrives would be too late, Nolan wrote, asking the federal government to start making a plan with the region.
“The need for action now is compelling. Many of the solutions require advance planning because they may require actions by regulators, finding new resources, chartering vessels, arranging for additional fuel deliveries and other yet-to-be-identified extraordinary actions,” he said.
Eversource’s request for help follows others in the region, including New England’s governors, who wrote to the Biden administration in August asking for consideration of a Jones Act waiver and work on a new Northeast energy reserve. (See New England Governors Ask Feds for Help with Winter Reliability.)
