Winter storms that dumped heavy, wet snow on Northern Nevada knocked out power to almost 124,000 NV Energy customers over the New Year’s holiday weekend, according to a report from the utility.
The outages reached a peak around 8 p.m. on Dec. 31, when 89,378 customers were without power, NV Energy said in a report filed with the Public Utilities Commission of Nevada. And 8,000 customers still didn’t have power on Jan. 3, according to PUCN.
NV Energy filed the report on Wednesday in response to an order from PUCN. The commission opened a docket on Jan. 3 to investigate the causes of the outages and the utility’s response.
In its report, NV Energy said “extreme weather” caused the outages.
“The storm was a very long-duration, atmospheric river storm that affected the entire region of Northern Nevada with heavy precipitation in the form of heavy, wet snow,” the report said.
Storm-related damage occurred across most western Nevada valleys and at Lake Tahoe, as tree branches snapped and snow piled up on power lines and equipment.
NV Energy dealt with 765 separate outages impacting an estimated 123,879 customers from Dec. 30 to Jan. 5. Twenty-nine of the outages were momentary, and the remainder were prolonged.
The outages mainly involved the distribution system and were caused by blown fuses, downed wires, broken poles, and damaged transformers and pole line hardware. In addition, downed wires and damaged structures caused some transmission-level outages, the utility said.
NV Energy worked to first address outages affecting the largest number of customers. As power was restored to many customers, the focus shifted to customers who had been without power for the longest time.
On Jan. 4, NV Energy made direct calls to 614 residential customers who had been without power for more than 48 hours, offering free lodging at a local hotel and checking to see if they needed water for livestock.
The utility also communicated with customers through the news media, its website and social media.
NV Energy initially dispatched four of its own crews to repair the outages on Dec. 31. Additional crews were then brought in from other parts of the state, along with seven contract crews, for a total of 18 crews on Jan. 2. A typical crew consists of four or five linemen.
In addition to the crews, the response included troubleshooters, fire crews for snow and debris removal, and NV Energy’s crisis and incident management teams.
Virginia Gov. Glenn Youngkin (R) on Wednesday gave his annual State of the Commonwealth speech, which included calls to change the state’s climate law and end its ties to California’s car emissions regulations.
“Our path forward will embrace the ‘and’ and reject the ‘or’ of energy politics,” Youngkin said to assembled lawmakers and state officials. “With our all-American, all-of-the-above approach, Virginians will get affordable and reliable and increasingly clean energy without being tied to unattainable long-term requirements.”
Youngkin said he wants to work with legislators to change state policies, including limiting long-term carbon goals to be updated every five years instead of setting more ambitious midcentury targets that are currently the law and common in other states’ policies.
Doing so would mean amending the Virginia Clean Economy Act (VCEA), which was passed before Youngkin took office when Democrats controlled the governor’s mansion and the legislature. When Youngkin won election in 2021, Republicans took the General Assembly, but Democrats still control the Senate because its elections are not until November 2023.
The governor called for investments in small modular nuclear reactors, hydrogen, carbon capture and storage, and more effective energy storage resources.
The VCEA requires Dominion Energy (NYSE:D), the largest utility in the state, and American Electric Power to increase the share of renewables in their generation fleets every year. But any other clean resources, including the state’s two existing nuclear power plants, are subtracted from the baseline of resources that must be replaced with renewables, Advanced Energy United Managing Director Harrison Godfrey said in an interview.
“We wanted to make certain that the VCEA didn’t essentially require double decarbonization,” said Godfrey, who worked to help pass that legislation. “If we’re already getting zero-emission generation from nuclear facilities, we don’t need to go back and also have renewables cover that.”
If any of the new resources that Youngkin wants to fund are able to come online, then they would also be subtracted from the renewable requirement of the VCEA, he added. However, small modular reactors and the other technologies have not been proven to be commercially viable yet.
Virginia has seen its energy prices rise, but Godfrey argued that the shift to clean energy and away from natural gas would lower energy prices because gas, which supplies about 60% of Dominion’s electricity, has seen its price go up recently and has dragged power prices along with it.
“We shouldn’t have policies that just run towards whatever the least-cost resource is in that moment and constantly shift with the winds; that’s what the governor is proposing here,” Godfrey said. “Setting clear, long-term goals and having a glide path to take us there is the way to both ensure that we have a system that is reliable, is affordable over the long-term and moves us towards being steadily cleaner.”
To the extent the VCEA’s directions need to be reviewed periodically to ensure that the grid remains reliable and electricity affordable, that can be taken care of by the state’s regulators without sacrificing the long-term goals that give the industry the certainty it needs to make necessary investments, Godfrey said.
When it comes to withdrawing Virginia from the group of 16 other states that have voluntarily agreed to follow California’s lead on automobile emissions — including its prohibition of new internal combustion engines for light duty vehicles in 2035 — Godfrey called that a false dichotomy.
Virginia cannot set its own standards: If it abandons the California compact, it would just default to the federal standards, which tend to fluctuate depending on which party controls the White House. The auto industry and U.S. consumers are all moving toward electric cars anyways, but the supplies of new vehicles are limited today, Godfrey said.
“Which states and dealers those vehicles are sent to depends entirely upon whether or not there is a standard in place,” he added. “So, if we want Virginians to have access to affordable, sustainable, clean electric vehicles, and plug-in hybrid electric vehicles, then the best way to do that is to be part of this interstate compact.”
FERC on Wednesday approved an expansion of the Transcontinental Gas Pipeline (Transco) despite a study from New Jersey state agencies finding it was not needed and that its utilities should use alternative sources of supply (CP21-94).
The Williams Companies’ (NYSE:WMB) proposed Regional Energy Access Expansion project includes upgrades to the existing pipeline in Pennsylvania and New Jersey to increase deliveries to the East Coast by 829,400 dekatherms per day, mostly into New Jersey, at a cost of about $950 million. The Transco pipeline includes 10,000 miles of pipe that bring gas from Texas and other areas on the Gulf Coast to New York City.
The New Jersey Board of Public Utilities and the Division of Rate Counsel argued that new capacity is not needed for the local distribution companies who signed contracts with Transco. The BPU commissioned a study from London Economics International that found that LDCs can easily meet their firm winter demands through 2030 using existing pipeline capacity. The board has directed them to consider non-pipeline alternatives to ensure they have enough gas capacity.
The New Jersey agencies’ arguments were backed by several environmental groups, who noted that the state is working to get to net-zero carbon emissions by midcentury.
Transco hired Levitan & Associates to do its own study, which found that LDCs in New Jersey and the Philadelphia area would fall short of needed supplies starting this decade and that the situation would only get worse without new infrastructure.
FERC said it found both studies useful in its decision, but it noted that they have different inputs that may reflect differences in risk tolerance for meeting demand on extremely cold days.
“After due consideration of both studies and other evidence as discussed, the commission finds that the construction and operation of the project will provide more reliable service on peak winter days and will provide cost benefits by increasing supply diversity,” FERC said.
Sierra Club argued that the pipeline was not needed because both Pennsylvania and New Jersey have laws that require cutting greenhouse gas emissions by 80% by 2050, but FERC said that is not enough to undermine its finding that Transco had demonstrated a need for the project. Some of the gas would flow to other states including Maryland, Delaware and New York, the commission noted.
The order drew additional statements from three of the four FERC commissioners.
While ultimately concurring with the order, Commissioner James Danly dissented from the majority’s decision to stay the project’s certificate so that the commission could process any requests for rehearing. He also argued that the commission should focus on precedent agreements as the main way for showing a project’s need, something that FERC under former Chair Richard Glick had proposed not to do.
Commissioner Allison Clements also concurred with the order while highlighting what she called the “inadequacies” of FERC’s 1999 policy statement on natural gas pipeline certificates.
“Twenty years ago, the commission was primarily concerned about assuring there would be sufficient natural gas transportation capacity to serve growing demand for natural gas,” Clements said. “Now, a combination of market forces and federal, state and local climate protection policies may lead to flat or declining demand for natural gas over time.”
Clements also argued that FERC should have given more weight to the BPU’s study finding no new pipeline capacity is needed in the state because she said the agency is the main regulator of the gas utilities that have signed up for 56% of the project’s capacity.
Commissioner Mark Christie wrote separately to concur with the commission’s decision to grant the BPU’s motion to intervene out of time, saying that “the views of state officials are always due respectful consideration.”
However, the former Virginia utility regulator said that the BPU’s views in the case were “somewhat less than clear” because it did not explicitly ask FERC to reject the project, only to accept the findings of its study that new pipeline capacity was not needed.
“Even assuming the NJBPU is implicitly opposed to the project, the record does not indicate that the NJBPU submitted any information explaining why the local gas distribution companies in New Jersey, which entered into contracts to take natural gas supply from this pipeline — LDCs which the NJBPU regulates — were wrong to do so or could have obtained alternative sources of gas supply to serve their residential, commercial and industrial customers,” Christie said.
VALLEY FORGE, Pa. — PJM expects to issue at least $1 billion in penalties over generation outages during Christmas weekend, when plummeting temperatures stretched the region to its limits, RTO officials told stakeholders this week.
PJM reported 46,000 MW of forced outages during Winter Storm Elliott on Dec. 24, representing more than 23% of its capacity and including almost 38% of its natural gas capacity. More than 92% of forced outages were reported to PJM with less than an hour’s notice — or with no notice at all.
PJM lost about one-quarter of its generating fleet — including 38% of natural gas units — after temperatures plunged over Christmas weekend. | PJM
“A large portion of our generation fleet failed to do what was required of them,” Donnie Bielak, PJM’s senior dispatch manager, told the Market Implementation Committee during a presentation Wednesday on the storm’s impact.
Although demand response and consumers’ conservation actions helped PJM avoid shedding load, the RTO was forced to cut exports to the Carolinas and the Tennessee Valley Authority, where there were load sheds.
Winter Storm Elliott was the fifth event in 10 years in which reliability was jeopardized by unplanned generating unit outages in cold weather. It came less than two years after Winter Storm Uri in February 2021 resulted in the largest firm load shed event in U.S. history.
Temperatures dropped 29 degrees F from about 36 degrees to 7 degrees within 12 hours on Dec. 23, the “most drastic” drop in more than a decade and lower than weather forecasts had predicted, PJM said. That contributed to a load forecast that fell 10% below actual load.
Temperatures dropped from about 36 degrees to 7 degrees within 12 hours on Dec. 23, the “most drastic” drop in more than a decade and lower than weather forecasts had predicted. That contributed to a load forecast that fell 10% below actual load that day. | PJM
Trying ‘to Stress Us Out’
Bielak told the Operating Committee in a second discussion Thursday that control room operators were “heavily, heavily strained” trying to maintain reliability through the valley period overnight Dec. 23 before the Christmas Eve morning peak.
“We just kept losing units. … It didn’t stop,” Bielak said.
He quoted a control room colleague, who remarked that it was like the dispatchers’ training in the PJM simulator, where instructors throw repeated outages at them “to stress us out.”
The Christmas Eve valley was the highest in the last decade and 40,000 MW higher than the second highest.
The extreme outages limited PJM’s ability to replenish pond levels at pumped storage sites before the Christmas Eve morning peak. “We were mortgaging the future,” Bielak said. “If we didn’t get through the valley there would be no peak anyway.”
30% Gas Supply Drop in Utica, Marcellus Shale
While some gas units tripped or were unable to start because of the cold, other units lacked fuel as a result of a 30% drop in gas production from the Marcellus and Utica shale regions. That repeated a pattern seen in Winter Storm Uri, when there were major production cuts in Texas and the Southwest.
Brian Fitzpatrick, PJM’s principal fuel supply strategist, said the RTO holds weekly meetings with pipeline operators between November and March to discuss electric and gas load forecasts and pipeline restrictions. “Those conversations ramped up” leading to the storm, he said, and the RTO monitored the interstate gas pipelines. But he acknowledged that “there is no bulletin board” providing the RTO real-time information on gas production. “We don’t see supply numbers until the next day,” he said.
Fitzpatrick said PJM’s challenge was the speed at which the load changed and how quickly the pipeline line pack diminished between late morning and late afternoon on Dec. 23.
Paul Sotkiewicz, of E-Cubed Policy Associates, said he was shocked by the reduced Marcellus production but noted some of his clients’ gas units faced pipeline reductions even where production cuts were not an issue.
Fitzpatrick said PJM does not know why production was cut but that it will likely be a focus of the FERC-NERC investigation. “My assumption is that it’s predominantly related to well freeze-offs. But were those well freeze-offs caused by something else? Was it a lack of manpower because of the holiday?” he said. “It wasn’t an absolute temperature issue necessarily. … The issue was how rapidly it got cold; right before the event it was very warm.”
Why Didn’t CP Fix This?
Christi Tezak, of ClearView Energy Partners, questioned why PJM’s Capacity Performance structure appeared to have led to higher outage rates compared to similar colds snaps in the past.
CP, which increased penalties for failing to deliver and bonuses for overperforming, was enacted in response to the 22% forced outage rate during the 2014 polar vortex.
“The whole point of CP was to provide those incentives on the front end” to prepare for winter weather, said PJM Senior Vice President of Market Services Stu Bresler. He said the RTO was seeking additional information from generators on their poor performance. “We have the same questions as you do,” he said.
Penalties
PJM estimates that the non-performance charges for generators will be between $1 billion to $2 billion. However, it cautioned that the figure is preliminary and includes facilities that may have permissible reasons to be excused. Given the scale of the penalties, PJM will be providing individual resource performance data to operators before it levies the charges, with the aim to have that sent out by the first full week of February.
“Right now this data only includes preliminary excuses for being scheduled down for economic dispatch,” PJM’s Susan Kenney said Wednesday.
Stakeholders in the generation sector complained they were both being held responsible for natural gas pipeline failures and being held to the capacity needs of other regions.
Throughout most of the weekend, PJM continued to be a net exporter of energy to surrounding regions, though efforts were taken to curtail the outward flow. Bielak said PJM are not “isolationists” and were not going to cut exports that would push other regions into load shedding.
One stakeholder who asked not to be identified questioned whether the penalties could cause disruptions to the markets should a significant number of generation owners go into default.
He asked “are we potentially moving towards a situation where markets are stressed due to” large numbers of participants going into default?
PJM CFO Lisa Drauschak said that while failure to pay does constitute a default, stakeholders are not responsible for any undercollection as it is subtracted from the bonuses paid out. In timing the payments, she said staff is taking into account non-payment risk and the RTO’s liquidity to ensure that there is no risk to stakeholders.
Erik Heinle of Vistra questioned whether the data gathering over the penalties could prompt a delay in 2025/26 Base Residual Auction slated for June.
“We agree it’s a question; it’s something we’re thinking about,” Bresler said. But the RTO hasn’t committed to changing any dates, he said.
Verifying Outage Causes
PJM said more than 92% of all outages were reported to the RTO with less than an hour’s notice, or with no notice at all.
Yet, when outages peaked at about 46,000 MW on the morning of Dec. 24, less than 15% of the lost capacity was attributed to start failures and unit trips, which occur without prior notice.
Bielak said dispatchers were calling operators who had not reported any problems and were informed “we can’t run.”
“Well, you should have had that note in … eDART [the dispatcher application and reporting tool] so we wouldn’t have bothered trying to call you,” Bielak said.
Dave Mabry, of the PJM Industrial Customer Coalition, said it appeared PJM suffered a “loss of situational awareness” during the storm.
“We really, really rely on members to tell us what the status of their units and parameters are … going into any kind of significant weather, but also on a daily basis because that’s how we make decisions,” said Senior Vice President of Operations Mike Bryson.
In response to a question from Tyson Slocum, energy program director for Public Citizen, Bryson acknowledged that PJM does not do any validation of the outage causes cited by generators. “If the unit was out, it’s going to be subject to a” penalty regardless of the cause, he said.
Slocum said companies with multiple units have an incentive to prolong scarcity events by providing misleading outage data because the CP penalties may be exceeded by CP bonus payments and revenue from high prices.
Sotkiewicz took offense at Slocum’s “implication that games are being played” by generators. “Trust me. We would want to be running,” he said, citing PJM’s estimate that penalties could total $2 billion.
PJM’s Chris Pilong said generators record the outage cause in eDART in real-time but provide more detail later in NERC’s Generating Availability Data System.
Monitoring Analytics President Joe Bowring said the Independent Market Monitor will be reviewing “every single outage,” adding, “we don’t think the reporting was entirely accurate.”
NERC Winter Standards Not Strict Enough
PJM officials said the Christmas storm experience underscored the RTO’s concerns that NERC’s proposed reliability standards on freeze protection for generation and natural gas facilities impacting the bulk power system are not strict enough.
Bryson said PJM’s concerns were included in the ISO-RTO Council’s (IRC) Dec. 8 comments in response to NERC’s Oct. 28 petition for approval of proposed Reliability Standards EOP-011-3 and EOP-012-1.3 (RD23-1). (See FERC, NERC See Progress on Winter Weatherization.)
The IRC said NERC’s proposal to use weather data since only 2000 “is not indicative of the actual extreme weather conditions that units may experience in the PJM region.”
Bryson said the RTO also is concerned with the “somewhat casual ability for generators to opt out of the standard.”
The IRC cited language allowing generators to reject the requirements based on a “commercial” constraint.
“Given that it is not at all clear how costly a measure must be before it presents a ‘commercial’ constraint, or how any such standard could be fairly applied both to independent power producers and to vertically integrated utilities subject to rate regulation, the IRC is concerned that these requirements as drafted will encourage generators to avoid making improvements, particularly if a competitor elects to utilize this ‘opt-out’ to gain a competitive advantage by avoiding the capital expenditures necessary for compliance,” it said.
Is Gas Unreliable?
Greg Poulos, executive director of the Consumer Advocates of PJM States, asked whether the events had raised questions about the reliability of gas. Bielak said it was too soon to draw any conclusions but said the RTO was taking additional steps to maintain reliability for the rest of the winter.
PJM officials said there will be additional discussions of the Christmas event at the Electric-Gas Coordination Senior Task Force meeting Jan. 19.
The energy storage units planned in great number in New York can also serve the state’s grid as transmission assets, a new study finds.
The white paper report — prepared for an organization advocating the advance and adoption of storage technology — uses actual and potential use cases to demonstrate the savings that could be realized by strategic use of storage rather than construction of new transmission lines.
William Acker, NY-BEST | NY-BEST
The New York Battery and Energy Storage Technology Consortium (NY-BEST) released the report Monday and followed up with a webinar Thursday. The report concludes that New York tariff and planning rules are an obstacle to exploiting storage as a transmission asset (SATA). William Acker, executive director of NY-BEST, told RTO Insider that the organization hopes to change this.
Along with a smaller price tag than transmission lines, storage offers a smaller footprint, a quicker installation time frame, and the flexibility to grow, shrink or relocate to adapt to what is likely to be a fluid state strategy during the clean-energy buildout, Acker argued.
Not mentioned in the report is the lifespan of batteries that are presently the dominant form of energy storage. They would need to be replaced long before transmission equipment would.
But the three use case studies projected that transmission wire solutions would cost 146 to 583% more than the initial capital costs for SATA, Acker said.
“You’re looking at numbers that allow for multiple replacement of storage,” he said.
Introducing the webinar, he noted New York’s plans to rapidly and radically increase use of green energy generation.
“We’re going to have an exceptionally large need for transmission and distribution buildout to support the decarbonization of the grid, the new renewable energy assets and the electrification of transportation and heating,” he said. “We’re looking at opportunities where storage can be used to make that buildout more efficient and cost-effective to consumers.”
Henry Chao, Quanta Technology | NY-BEST
Quanta Technology Vice President Henry Chao, who took the lead in preparing the study for NY-BEST, spoke of multiple potential benefits of SATA, including the flexibility to handle the gradual buildout of new power sources over the course of many years.
“Storage can help you to shave the peak and then add incrementally,” he said. “Eventually, five [to] 10 years later, you have to build transmission, but in the interim, those incrementally added renewables will not have to be subject to curtailment.”
Lars Stephan, senior manager of policy and market development at the energy storage firm Fluence, described one of the real-world use cases cited in the study: a 450-MW storage procurement that will allow Germany’s near-capacity grid to handle the increasing flow of renewable energy as the buildout of new transmission drags far behind the initial timetable.
Lars Stephan, Fluence | NY-BEST
“We’re seeing mounting costs of congestion in the German grid,” Stephan said. The cost totaled about 2.3 billion euros in 2021, he said, and multiplied in 2022 as the energy market reeled from the Russian invasion of Ukraine.
“As a measure to counter this, the German grid operators came up with the idea to use batteries as so-called grid boosters. … The fundamental principle is to use batteries to replace the N-1 requirement in grid operation.”
New York Gov. Kathy Hochul is proposing to double the target for energy storage installed statewide by 2030 to 6 GW, and most decarbonization scenarios call for much more storage capacity installed by 2040, to compensate for daily and hourly fluctuations in wind velocity and sunlight intensity. (See NY Proposes Credit System to Fund 6 GW of Energy Storage.)
In this environment, energy storage can serve as a power asset or a transmission asset, Acker said. “It gets complicated because storage in many cases can be both.”
What NY-BEST would like to see is for storage to be able to be compensated as either in New York. There are situations, Acker said, where payment through the power market mechanisms will not work and compensation through other rate mechanisms as a transmission asset is necessary. But it is not possible now.
In a special teleconference on Thursday, NERC’s Standards Committee unanimously agreed to submit for industry comment a proposal to update the organization’s Rules of Procedure intended to streamline the reliability standard development process and allow a faster response to emerging issues.
The changes apply to section 300 of the ROP, covering standards development, and to Appendix 3A, NERC’s Standard Processes Manual (SPM). With the committee’s approval, the planned updates to the SPM will be posted for a 45-day formal comment period, with ballot pools to be formed in the first 30 days and an initial ballot conducted during the last 10 days of the comment period. Comments on these revisions will be submitted through NERC’s Standards Balloting System.
The proposed ROP changes will be posted for their own 45-day comment period, to run concurrently with those to the SPM. Because these revisions are not subject to ballot body approval, stakeholders are requested to comment on them via email. In response to a question from Marty Hostler of the Northern California Power Agency, NERC Senior Counsel Lauren Perotti confirmed that these emailed responses will be organized into a “matrix consideration of comments” and posted to NERC’s ROP page.
The biggest change to the ROP is the addition of a new section 322, which would give NERC’s Board of Trustees “the authority to direct the development of a reliability standard in extraordinary circumstances where the board finds that issuing a directive is essential to address an urgent reliability issue.” Currently only FERC has the authority to direct standards development unilaterally, under section 321; the proposed section 322 is modeled on the existing rule.
NERC Trustee Sue Kelly | NERC
NERC’s board ordered the Standards Committee to pursue the ROP updates at its November meeting, following a proposal by the Standards Process Stakeholder Engagement Group in October. Trustee Sue Kelly, the committee’s liaison to the board, told members last month that the board was trying to address concerns that NERC’s “deliberative” standards development process was not keeping up with the increasingly rapid pace of industry change. (See NERC Board Member Argues for Increased Authority.)
Other revisions to the ROP include adding a provision in section 316 requiring that the standards development process be accredited by the American National Standards Institute (ANSI). This proposal drew another question from Hostler, who asked why, if “you have an accredited system already for standards … would you not want to follow that?”
In response, Latrice Harkness, NERC’s manager of standards development, explained that “in order to move forward with … the streamlining of the standards development process, there were certain things that we had to move away from,” including maintaining ANSI accreditation. However, she assured listeners that the development process is still modeled on ANSI procedures.
Perotti added that “while we may not be following some of the more granular ANSI procedural requirements, we still will be adhering to the general framework of due process, public comment, balanced stakeholder voting and so forth.”
The SPM changes include creating a tiered system of comment periods, under which the initial 45-day comment and balloting periods would be followed by shorter comment periods “when the issues are likely to have narrowed.” A revised Section 4.13 would remove the requirement for a final ballot to confirm the results of the most recent successful ballot, if the standards development team “has made a good faith effort at resolving objections [and] is not making any substantive changes” to the finished standard.
Southern Co. (NYSE:SO) said Wednesday that Unit 3 at Vogtle nuclear plant in Waynesboro, Ga., has suffered yet another delay and is now not expected to come online until at least the second quarter of 2023, rather than the first quarter as previously predicted.
The utility disclosed the change in plans in a filing with the Securities and Exchange Commission.
According to the filing, Southern Nuclear was in the process of start-up and pre-operational testing for Unit 3 when it detected “vibrations associated with certain piping within the cooling system,” which it is currently “in the process of remediating.”
Details of the vibrations were not provided in the filing. Southern said it plans to file a license amendment request with the Nuclear Regulatory Commission in hopes of speeding up the remediation process, but that initial criticality will not occur until February, and Unit 3 will not enter service until April.
Jacob Hawkins, a spokesperson for Georgia Power, said in an email to RTO Insider that the utility’s remediation plans include “strengthening the support for the pipes,” which must be done before progressing to initial criticality. Hawkins said Georgia Power is “focused on getting this project done right, with safety and quality first.”
The delay is expected to raise base capital costs for Georgia Power, the operator of the plant, by up to $15 million per month, not including additional costs for construction, support resources, or testing. Southern said it will share additional updates during its earnings call in February and warned of “ongoing or future challenges,” including management of contracts and vendors, and subcontractor performance.
Vogtle Unit 3 has been under construction since 2009, along with Unit 4; Units 1 and 2 at the site have been in operation since 1987 and 1989, respectively. They are the only reactors currently under construction in the U.S., and Southern is calling them “the first new nuclear units built in the United States in the last three decades.” When units 3 and 4 come online, Vogtle will be the only four-unit nuclear facility in the country.
The new units were originally intended to be operational by 2017, but the project has undergone numerous delays that provided considerable fuel for its detractors. Additional criticism has attached to the plant’s cost overruns; in its semi-annual progress report to the Georgia Public Service Commission in August, Georgia Power said total construction expenses up to that point were $8.2 billion, above the original approved cost of $7.3 billion, and the final cost would likely be more than $10.7 billion.
However, the project has its supporters as well; Nuclear Energy Institute CEO Maria Korsnick in 2021 praised management and staff at Southern for pressing on, “undeterred by a global pandemic [and] getting the job done.” (See Nuclear Key to Clean Energy Future, NEI Says.)
Georgia Power announced in October that it had begun loading fuel into Unit 3’s reactor core following the receipt of a 103(g) filing from the NRC in August, indicating that “the new unit has been constructed and will be operated in conformance with the combined license and NRC regulations.” Unit 4 completed cold hydro testing in December, the utility said, leaving hot functional testing, scheduled to begin this quarter, as the last major test remaining for the reactor.
ISO-NE is digging into the details on how it plans to measure the limitations of gas generators in its new capacity accreditation process.
At this week’s NEPOOL Markets Committee meeting, the grid operator continued laying out its proposed methods for de-rating gas resources in the winter, when they may have challenges getting fuel.
Under ISO-NE’s proposed framework, the capacity qualification process would include a determination of gas plants’ firm and non-firm capacities for the December to February period each year. The RTO is developing firm fuel requirements that the generators would have to meet in order to get a firm capacity rating.
And there would be a new way to rate what ISO-NE is calling “operationally limited resources,” which are those that are expected to be unable to get gas at all and would in turn be assigned zero qualified capacity for the winter period.
“Operationally limited resources are unlikely to receive gas on many cold days, let alone days when minimal non-firm gas is available for generators,” said Alexander Mattfolk, a consultant with Levitan & Associates, which is helping ISO-NE develop the new framework.
Also at the MC meeting this week, ISO-NE continued its explanation of its proposed day-ahead ancillary services market, which is intended to fill energy gaps in the day-ahead market and procure reserves that can start up quickly, in 10 or 30 minutes.
The project borrows heavily from ISO-NE’s previous Energy Security Improvements project, which ultimately failed at FERC.
In addition to reiterating the basics of the market, which includes a new constraint called the forecast energy requirement and a new product called the energy imbalance reserve, ISO-NE shared its plan for forecasting real-time LMPs.
The grid operator is planning to use a “Gaussian Mixture Model,” into which it will plug the day-ahead market load forecast, 24-hour lagged LMPs, the prices of gas and oil, weather forecasts and historical LMP data.
Less than two weeks after Gov. Michelle Lujan Grisham appointed new members to the New Mexico Public Regulation Commission, one member has resigned and the governor has named a replacement.
Lujan Grisham on Tuesday appointed James Ellison, principal grid analyst for the Grid Modernization Group at Sandia National Laboratories, to the three-member PRC. The appointment follows the resignation of Brian Moore, who said he didn’t meet the educational requirements for the job.
The PRC had been a five-member elected body since its formation in 1996 but transitioned on Jan. 1 to a three-member appointed panel. Lujan Grisham announced her appointments on Dec. 30. (See NM Rings in New Year with Reconfigured Utility Commission.)
The revamped PRC held its first meeting on Wednesday with commissioners Patrick O’Connell and Gabriel Aguilera participating because Ellison hadn’t been sworn in. The two commissioners decided that O’Connell will serve as PRC chairman.
Another item on the agenda was choosing a commissioner to serve on the SPP Regional State Committee. Aguilera expressed interest in the role, saying regional markets are one of his areas of expertise. But the commissioners agreed to wait until the next PRC meeting, when Ellison is expected to participate, to choose a representative.
Aguilera said the decision is an important one.
“In terms of regional markets, a lot of them are being designed right now, as we speak,” he said. “So, I do think that it is very important for us to be in those conversations to make sure that whatever solutions come out of those discussions represent a good outcome for New Mexicans.”
While Ellison did not participate in Wednesday’s meeting as a commissioner, he attended as a special guest and commented on the role of the PRC.
“The PRC is tasked with ensuring that the transition to renewables takes place, and that it takes place while preserving reliability and while ensuring that the cost of power be as low as reasonably possible,” Ellison said. “It’s certainly an honor to play a role in this transition.”
Moore, the PRC appointee who resigned, served in the state House of Representatives from 2001 to 2008 representing eastern New Mexico. He submitted a resume to the PRC Nominating Committee saying that he majored in business finance with statistical analysis at the University of Denver, but he never graduated from the school, a spokesperson for the governor told the Albuquerque Journal.
Under New Mexico statutes, PRC members must have a bachelor’s degree from an accredited institution of higher education and at least 10 years of experience in the energy sector or an area regulated by the commission.
Alternatively, the commissioner may have completed higher education resulting in a professional license or a post-graduate degree in a field related to an area regulated by the commission and have at least 10 years of experience.
A seven-member PRC Nominating Committee selected nine potential commissioners and sent their names to Lujan Grisham for consideration. The governor noted that the Nominating Committee vetted the candidates.
Hydro-Québec’s CEO stepped down this week, sending a shockwave through the Canadian energy sector that could reverberate into New England.
Sophie Brochu’s resignation came amid tensions between the utility and the Québec government, which has pushed to “lure new power-hungry industrial users to the province,” the Montreal Gazettereported on Tuesday.
Brochu had been CEO of HQ since 2020 and had said as recently as October that she would stay on “as long as the company’s governance framework remained ‘healthy,’” the Gazette wrote.
The leadership upheaval comes as New England continues to heavily rely on imports from Québec to keep its own grid in good condition. HQ and its U.S. partners have also struggled to site the New England Clean Energy Connect transmission line, intended to bring down even more Canadian hydropower to the areas of heaviest electricity demand in southern New England.
In 2021, New England imported 16% of its electricity from neighbors, with most of that (13,617 out of a total 18,718 GWh in imports) coming from Québec.
Push and Pull
HQ spokesperson Lynn St-Laurent told RTO Insider that the company “has been a committed energy partner to New England for several decades and there isn’t any reason at all to assume that this will change.”
The company’s strategic moves, however, have led some in the New England energy sector to wonder about the Canadian province’s ability to continue sending its power to the Northeast U.S.
In its recent history, HQ has had a “pretty aggressive stance to maximize the revenue of exports,” said Dan Dolan, president of the New England Power Generators Association.
And the Canadian utility recently looked to build its presence in New England by buying Great River Hydro and its fleet of 13 generating stations in the region.
But in a strategic plan led by Brochu last year, HQ warned that its energy and capacity balances are going to tighten over the next few years, and that the region will need new supplies by 2026.
“Electricity demand is … expected to rise, even though the rate at which the new needs will materialize is uncertain. As a result, we must prioritize the uses that stand to create the greatest value for Québec,” the plan said.
How HQ responds to those needs is likely to have an impact on New England, said Dolan
“In a time of transition, it will be fascinating to see if there’s a continuation of that [aggressive stance] or if we see a shift to taking a more inward look, because Québec for the last several years and during Christmas Eve, has had serious internal supply issues,” Dolan said.
But St-Laurent noted that the strategic plan also calls for HQ to “increase our presence and operations in neighboring markets.”
Christmas Eve in the Spotlight
The events of Dec. 24 in New England are a clear example of the region’s reliance on Québec.
One of the key triggers in the buildup to the Christmas Eve energy shortage was a sudden drop in imports from HQ.
It occurred as the Canadian province was dealing with a major storm and transmission outages, which forced it to reduce its exports to New England.
“In Québec, they were fighting both an actual load that was well above their forecast and the outages on their transmission lines. They were battling their own issues,” said ISO-NE COO Vamsi Chadalavada at a recent NEPOOL meeting.
“The reduction of imports on Phase 2 over the day were because of what Québec was experiencing, but it did have a significant impact on us.”
The loss of imports combined with generation outages in New England ultimately led the grid operator to go into its Operating Procedure 4 for the first time since 2018, and to subsequently dish out $39 million in pay-for-performance penalties to generators.
HQ says it upheld its contracted capacity sale obligations and helped maintain reliability in New England during the event.
“HQ maintained a reasonable level of export throughout the period despite the loss of transmission capacity in Québec,” St-Laurent said. “In regards to its current capacity sale commitments in New England, HQ actually delivered more than what was committed during this period — 856 MW.”
The reductions were caused by HQ pulling back temporarily in the short-term spot market, she said.
But for NEPGA’s Dolan, the event was another example of the precarious nature of bringing in electricity from other regions.
“They didn’t pull back imports because they felt like it. They did it because they had a very high load show up on Christmas Eve,” he said. “It’s a provincially owned utility, and that’s exactly what they should do. But it does create questions and consequences for us as an importing region.”
St-Laurent said demand in Quebec on Dec. 24 was 31,510 MW, 9,000 MW short of its winter peak.
This story has been updated to include comment from Hydro-Quebec.
