ISO-NE and the New England Power Pool Participants Committee want to begin using the RTO’s system-wide sloped demand curve in their Annual Reconfiguration Auctions.
The organizations submitted proposed Tariff changes to FERC that would apply the curve — first used in the ninth Forward Capacity Auction earlier this year — to the ARAs beginning in June 2016 (ER15-2404).
Under the current rules, demand in ARAs is represented by the fixed value of the installed capacity requirement.
The proposed changes “simply incorporate the system-wide demand curve used in an initial Forward Capacity Auction into the Annual Reconfiguration Auctions so that demand will be represented consistently in both FCAs and ARAs,” the petition said.
“Such consistency in the demand model from auction to auction avoids predictable, structural price differences,” Matthew C. Brewster, lead analyst in ISO-NE’s market development department, wrote in accompanying testimony.
Demand in import- and export-constrained capacity zones will continue to be established by local sourcing requirements and maximum capacity limits, respectively, the RTO said.
The RTO will conduct three ARAs to allow for the exchange of capacity supply obligations prior to the 2018/19 capacity commitment period covered by FCA 9.
The changes would not affect how suppliers participate in reconfiguration auctions. But unlike current rules, in which clearing occurs only through matching of counterparty offers and bids, clearing would occur using the demand curve, even without a counterparty.
The changes received the unanimous support of the NEPOOL Participants Committee and near-unanimous support from the NEPOOL Markets Committee.
Power generators have opposed a system-wide sloped demand curve and advocate a zonal demand curve to reflect capacity constraints in parts of New England. (See ISO-NE, NEPOOL Oppose Demand Curve Change.)
VALLEY FORGE, Pa. — PJM planners have selected 11 small market efficiency projects and narrowed the list of proposals for its biggest congestion problem to 12 candidates.
The 11 projects — all transmission owner upgrades — have a combined cost of $59.2 million, with a benefit-cost ratio of 15.6 and estimated 2019 congestion reductions totaling $50 million. The PJM Board of Managers is expected to consider planners’ recommendations of the projects at their meeting in October.
“These are all locational type projects … they’re cheap fixes basically,” PJM’s Tim Horger told the Transmission Expansion Advisory Committee on Thursday. Over 15 years, “you’re going to see hundreds of millions” in savings.
The 12 proposed fixes for the AP South/AEP-DOM constraints will undergo further analysis, including an initial cost review and sensitivity analyses for changes in load forecasts, fuel prices and interface ratings.
About 20 of the larger proposals passed the 1.25 benefit-cost threshold. The 12 finalists are those that continued to meet the 1.25 threshold using a base case incorporating the 11 small projects and also reduce congestion for combined 2019 and 2022 simulations with minimum production costs and load payment savings of $20 million.
They range in cost from $15.7 million to $300.7 million.
Vice President of Planning Steve Herling said it was possible — though unlikely — that the AP South/AEP-DOM fixes could displace one or more of the 11 smaller local projects. “We’ll pull one of [the smaller projects] out of there if we have to,” he said.
Sharon Segner of LS Power questioned PJM’s method of winnowing the list, saying the RTO’s Tariff requires such projects be based only on the zone seeing reduced load payments.
(Click to zoom.)
“When you have multiple projects that all pass, the Tariff doesn’t tell us how to decide [among them],” Herling responded. “We’re having to use our judgment.”
Segner said PJM had told stakeholders that selections would be made based on the highest cost-benefit ratios. “That’s what motivates the market,” she said. “Otherwise it becomes pretty subjective and loosey-goosey.”
In total, PJM received 93 market efficiency proposals, including 35 transmission owner upgrades ranging from $100,000 to $68 million and 58 greenfield projects with costs of $9.2 million to $432.5 million.
Second Proposal Window Opens
PJM opened a second transmission proposal window Aug. 5, seeking solutions to 2020 transmission owner criteria violations and reliability problems identified from planners’ light load analysis. The RTO will accept proposals through Sept. 4.
No Projects Arise from ARR Review
The annual review of auction revenue rights feasibility resulted in no transmission upgrade projects, planners said. Already-approved upgrades were identified for violations on most of the 45 paths analyzed over the 10-year horizon. Three paths in the ATSI zone that saw violations in years nine and 10 will be monitored for potential upgrades in the future.
PJM: Despite Lack of Cost Allocation Rules, MISO Project Too Good to Ignore
PJM doesn’t know how it would allocate costs from its share of a potential transmission upgrade MISO is considering in southern Indiana, but the project’s potential to fix longstanding stability problems at American Electric Power’s Rockport substation is too compelling to ignore, planners said.
“The challenge is this is a market efficiency project in MISO and a reliability project in PJM” — a combination for which there are no cost allocation rules in the PJM-MISO joint operating agreement, Herling said. “This is just such a good opportunity we don’t want to let it go by.”
The area has added thousands of megawatts of generation but no new transmission since 1989. As a result, the Rockport substation has operated under a special protection scheme involving relays, and tripping and ramping down of generators. About 4,400 MW of generation was tripped in a 2007 incident.
PJM will have to move quickly; MISO planners intend to recommend the winning project to the MISO Board of Directors in December.
Initial results of PJM’s analysis are expected in time for MISO’s Aug. 19 Planning Advisory Committee meeting.
“It could be a win-win,” said PJM’s Chuck Liebold.
Planners Reevaluating Pratts Project
PJM is reconsidering its selection of the Gordonsville-Pratts-Remington transmission upgrade after learning that it will require 15 to 18 miles of new right of way, far more than initially believed.
In February, planners recommended the proposal from Dominion Resources and FirstEnergy at an estimated cost of $129 million to $164 million.
“We want to double check to make sure we’re doing the right project,” said General Manager of System Planning Paul McGlynn, who said planners will evaluate a Gordonsville-Remington route among the alternatives.
The Virginia State Corporation Commission, which would have to approve the project, says that existing rights of way should be given priority as the locations for transmission additions.
A representative for Madison County, Va., urged PJM to reject the original plan. He said the scale of the project is out of proportion to the rural county — population 13,000 — which is dependent solely on farming and tourism and has no public water or sewers. “That’s the question — the need versus what’s being proposed,” he said.
McGlynn noted, however, that the project is not being driven solely by load in the Pratts area.
PJM solicited solutions in its second Order 1000 proposal window last year.
Four developers suggested 16 proposals, including two transmission owner upgrades and 14 greenfield projects. Only six of the proposals were judged to have solved the violations. Two losing bidders, ITC Holdings and LS Power’s Northeast Transmission Development, have challenged the choice in letters to the PJM board. (See Tx Developers Challenge PJM Choice on Pratts Project.)
Planners will reevaluate the options in September and make a recommendation to the board in October.
It had been four years since ERCOT last set a new demand record, but the Texas grid has been making up for lost time since August began. In the last two weeks, ERCOT has set three new hourly peaks, topping 69,000 MW in demand for the first time ever on Aug. 10.
ERCOT says while the summer temperatures are partly attributable to the increase, the state’s explosive population growth is the real driver.
“A large part of the demand we’re seeing is customer growth over the last few years,” said ERCOT COO Brad Jones last week.
Jones made his comments a few hours after ERCOT issued a conservation alert and asked customers to limit electricity usage during the 3-7 p.m. peak-demand hours Aug. 13. Triple-digit temperatures and outages at several power plants brought the ERCOT system perilously close to its 2,500-MW reserve threshold.
The system set a new all-time peak hourly demand Aug. 10 when it eclipsed the 69,000-MW mark for three consecutive hours, hitting a record 69,783 MW between 4 and 5 p.m. Operating reserves remained above 3,000 MW during the day, Jones said.
ERCOT previously set demand records Aug. 6 (68,912 MW) and Aug. 5 (68,459 MW). Until then, the ISO’s previous record was 68,305 MW, set Aug. 3, 2011.
At this pace, ERCOT will surpass August 2011’s record production of 38.2 GW of energy.
Jones said ERCOT imported power through its two links with SPP but avoided calling for load curtailments or other emergency operations thanks to conservation by consumers. Market prices jumped to about $1,700/MWh during the day.
Population Growth
The U.S. Census Bureau says Texas’ population has grown by 1.8 million people from 2010 to 2014, a 7.2% increase. The state’s population — almost 27 million at the end of 2014 — is expected to double by 2050.
According to the state comptroller, more than 100,000 single-family building permits and 64,000 multi-family permits have been issued in the 12 months ending June 2015.
The comptroller also said Texas’ real gross domestic product grew by 5.2% in 2014, compared with 2.39% for the U.S. The state’s unemployment rate was 4.2% in June, down from 5.0% in June 2014; it has been at or below the national average for 102 consecutive months.
Jones noted ERCOT serves some of the fastest-growing cities in the country. Houston, San Antonio, Dallas, Austin and Fort Worth are among the 16 most populous cities in the U.S.
Some 4,800 MW of new generation will be coming online in the next three to four years, Jones said.
ERCOT said it will continue to monitor conditions as summer demand continues and call for conservation when needed. It has asked Texans to raise thermostats 2 to 3 degrees during peak hours, use fans, limit the use of large appliances to off-peak hours and close blinds and drapes during the afternoon.
“Voluntary conservation can help us reduce the potential for additional measures, such as rotating outages, to ensure reliability throughout the ERCOT grid,” said ERCOT’s Director of System Operations, Dan Woodfin, in one of many press releases the ISO has issued this month.
SPP: Hot, but not Breaking Records
The SPP footprint has seen some of the same triple-digit figures as Texas, but the RTO has not topped its record demand peak of 54,949 MW, set Aug. 3, 2011. Its high for the year came in July, when the SPP Balancing Authority recorded a peak of 45,873 MW.
LITTLE ROCK, Ark. — SPP announced Monday it has appointed former FBI agent Mark Bowling as its director of compliance and security. Bowling will oversee SPP’s compliance policies and procedures, including national and regional reliability standards and tariff provisions, and he will be responsible for corporate security monitoring and response.
Bowling
Bowling, who served as an FBI special agent for 20 years, also worked for the U.S. Department of Education Office of Inspector General. He has investigative experience in computer intrusion, computer fraud, counter-terrorism, national security and counterintelligence. Prior to joining the FBI in 1995, Bowling was a naval nuclear engineering officer with the United States Navy for six years.
Michael Desselle, SPP’s vice president of process integrity and chief compliance and administrative officer, said Bowling’s “expertise in identifying and mitigating cyber threats will be extremely beneficial in leading the effort to protect our critical infrastructure assets.”
The power outage that darkened the White House and much of D.C. on April 7 began with the failure of a 230-kV lightning arrester in the Pepco portion of the Ryceville, Md., substation 40 miles south of the district, according to a briefing by the North American Electric Reliability Corp. last week.
The outage, which caused a “severe, prolonged voltage sag” in the D.C. area, began about 12:39 p.m. when Pepco’s protection systems failed to isolate a fault on the 230-kV line.
Two separate and redundant protection systems failed, the first as a result of a loose connection to an auxiliary trip relay circuit, the second due to “intermittent discontinuity” in an auxiliary trip relay circuit, according to a presentation to NERC’s Member Representatives Committee.
NERC presentation shows damaged lightning arrester at Pepco substation.
Pepco and Southern Maryland Electric Cooperative lost 532 MW of load for as long as two hours. Some customers automatically switched to back-up power sources, while customer protection systems separated others from the grid due to low voltage. The outage affected the Maryland peninsula bounded by the Potomac River on the west and the Chesapeake Bay on the east.
Panda Power’s Brandywine 202-MW combined-cycle plant and the Calvert Cliffs nuclear units 1 and 2 (1,779 MW) tripped offline. Brandywine returned to service after about an hour; Calvert Cliffs returned two days later.
Investigators found damage to an A-frame structure at the Ryceville substation, including pitting near burned arresters and a downed static wire. An A-phase conductor was found detached outside the fence line.
There was no evidence of burning to the A-phase arrester, suggesting that mechanical failure resulted from the arc burning off the insulator and the weight of the line breaking the arrester free from the structure.
Talen Energy released its first earnings report as an independent company last week, reporting net income of $26 million ($0.26/share) for the second quarter of 2015.
That’s based mostly on “legacy” data from the company’s plants, which were owned by PPL and Riverstone Holdings before Talen’s formation on June 1. Collectively, these plants’ profits doubled from $13 million ($0.13/share) in the second quarter of 2014. The company’s operating revenue stayed consistent for both periods, at $1.07 billion.
“Strong operational performance from our nuclear and gas generation assets led to improved financial results in the quarter,” CEO Paul Farr said in a statement.
During a conference call with investors, Farr said the Susquehanna nuclear plant performed well in spite of Unit 2’s cracked turbine blades, which have now been repaired. Talen will replace the blades for both Units 1 and 2 during the plant’s next scheduled fuel outage.
Farr also said that Talen will announce by the fourth quarter what assets it will be divesting to meet FERC’s conditions for approval of the company’s creation.
Despite the company’s optimism, Talen’s stock price remains low, closing at $15.95 last week. That’s well below the $20/share when the company went public.
“We do not believe our current share price reflects the underlying value of our business, and capital discipline will remain our top priority,” Farr told investors.
Upcoming Transactions
Talen reported adjusted EBITDA of $171 million for the quarter, a 35% increase over the same period last year.
Talen predicts EBITDA of $990 million for 2016 based on two deals expected to close by the end of the year.
One is the acquisition of three plants from MACH Gen that will see the company enter the NYISO market. (See Talen Entering NYISO in $1.2B Deal.)
The other is the sale of its renewable energy business to California-based Energy Power Partners. The deal was announced in June, and Talen filed for FERC approval earlier this month (EC15-182).
The $116 million sale ($1,785/kW) includes 25 wind, solar and biofuel facilities totaling 65 MW in PJM and ISO-NE.
The New York Public Service Commission staff has accepted seven proposed demonstration projects for the Reforming the Energy Vision initiative while asking for more refinements on four others.
The projects, filed July 1, are a component of the state’s REV program for utility-sponsored projects that offer collaboration with third parties. (See REV Proposals Seek to Increase Conservation.)
In letters to the state’s utilities, PSC staff said seven demonstration projects met criteria set out in the REV order. Staff said it would meet with sponsors of the remaining projects to discuss additional information needed to complete its review:
Three proposals by National Grid: a smart grid project in Clifton Park to give customers fixed-rate options based on energy consumption, its Buffalo Niagara Medical Campus engagement platform and its microgrid partnership with Clarkson University and the State University of New York at Potsdam;
Consolidated Edison’s CONnectED Home Platform that would connect homeowners with efficiency programs; and
Iberdrola’s proposed Energy Marketplace e-commerce website.
LITTLE ROCK, Ark. — While SPP says it is continuing to analyze the 1,500 pages in the Environmental Protection Agency’s Clean Power Plan, some stakeholders in the RTO’s 14-state footprint wasted no time taking action.
Arkansas Department of Environmental Quality Director Becky Keogh listens as Public Service Commission Chairman Ted Thomas speaks at press conference Monday.
In the first of several expected legal challenges, state attorneys general from half of SPP’s states and six of MISO’s were among 15 who last week asked a federal court in D.C. to block the rules. Arkansas, Kansas, Louisiana, Nebraska, Oklahoma, South Dakota and Wyoming joined West Virginia in filing a petition seeking a stay of the plan pending the outcome of expected legal challenges.
Also joining the petition were Wisconsin (MISO), Ohio (PJM) and Indiana and Kentucky (MISO and PJM). Alabama and Florida, outside of any organized markets, also joined.
But even as elected officials’ rhetoric remains hot, there were signs that the behind-the-scenes work toward compliance has already begun.
Opposition from Okla., Ark.
Oklahoma Attorney General Scott Pruitt, who had filed an unsuccessful legal challenge even before the final rule was issued, continues to argue that the EPA rule is unlawful. EPA’s rules “[force] Oklahoma into fundamentally restructuring the generation, transmission, and regulation of electricity in such a manner that would threaten the reliability and affordability of power in the state,” he said.
Arkansas Gov. Asa Hutchinson also came out guns blazing. “It is clear that the Obama administration’s Clean Power Plan could still result in significant electric rate increases for middle class ratepayers while having a minimal impact on global temperatures,” he said. “My administration will do everything it can to protect ratepayers.”
Hutchinson has directed the leadership of the state’s Department of Environmental Quality (ADEQ) and Public Service Commission “to discuss the details of the rule and the stakeholder process.”
In a press conference Monday, ADEQ Director Becky Keogh and Ted Thomas, chairman of the Public Service Commission, said they have been told to seek the lowest-cost option and will explore strategies that meet the Clean Power Plan while planning for the state’s future and allowing for growth.
Arkansas would need to reduce its emissions by 36.5% from its 2012 levels to meet the rule. Keogh said the state would begin gathering stakeholder input in early October as it decides whether to submit a plan to EPA by the September 2016 deadline or ask for a two-year extension.
“We have a lot more time,” Thomas said, “which is important when you’re making decisions that affect the citizens of the state.”
But Keogh said that while Arkansas has joined litigation against the Clean Power Plan, ADEQ and the PSC will still need to work quickly.
“We feel it’s prudent for the state to begin a deliberative process to evaluate our options and the potential impacts of those options,” she said. “Should the rule become final — and the deadline will be upon us very soon — it’s too important to wait for a final rule and then determine a path forward.”
SPP Analyses
SPP has taken a broader approach when analyzing the Clean Power Plan and its impact on the footprint’s reliability and economics. In an emailed statement, Lanny Nickell, the RTO’s vice president of engineering, noted SPP’s highest priority is maintaining the Bulk Electric System’s reliability in the central U.S.
“Compliance with the Clean Power Plan is best facilitated through SPP’s regional transmission planning process and energy market administration,” Nickell said. “Transmission planning requires analysis of many variables and takes considerable time.”
SPP’s planning process currently operates on near-term and 10- and 20-year cycles. Several stakeholder-driven initiatives are evaluating how to improve the planning process and best take into account Clean Power Plan impacts.
“I imagine there will be modeling based on the new rule,” Thomas said. “We don’t know yet what that’s going to be, but SPP, MISO and other groups we work with have extensive access to modeling, where you can put in price impacts and see the result.”
SPP has issued three reports on the Clean Power Plan since last October.
The first, a transmission-system impact evaluation, warned of rolling blackouts or cascading outages “unless the proposed CPP is modified significantly.” SPP said the original 2020 date for interim goals was unworkable and did not allow enough time to build the needed generation and transmission to accommodate coal plant retirements and deliver wind energy to population centers. (See MISO, SPP: EPA Clean Power Plan Threatens Reliability, Needs Longer Compliance Schedule.)
In April, SPP released a second analysis that indicated a regional-compliance approach with the 2030 deadline would cost an estimated $2.9 billion per year in capital investment and energy production costs. (See SPP: $45/ton Adder, Wind, Gas Meets EPA Carbon Rule.)
SPP issued a third study last month that concluded a state-by-state compliance approach would be a 40% increase over the regional plan. The latest assessment analyzed the EPA rule’s impact on existing generation and resource-expansion plans, without including the cost of new transmission needed to maintain reliability, gas-infrastructure expansion, market-design changes or transmission congestion. (See SPP: State-by-State Compliance Would Hike Carbon Reduction Costs by 40%.)
VALLEY FORGE, Pa. — The Market Implementation Committee last week approved rule changes that will help the Illinois Municipal Electric Agency to meet its capacity requirements with historic resources.
IMEA is among the load-serving entities that procured capacity resources outside of their locational deliverability areas to serve a portion of their load.
PJM’s Reliability Pricing Model capacity construct, which launched after IMEA obtained its external capacity, does not provide a way to allocate and maintain the benefits of historical resource and transmission service agreements — an issue that can increase an LSE’s costs if its LDA becomes modeled separately and binds in an auction.
The Independent Market Monitor had expressed concern that PJM’s initial proposed solution was overly broad. But it agreed with the revised solution, which covered only LSEs subject to fixed resource requirements (FRR).
FRR entities such as IMEA are subject to a percentage internal resource requirement (PIRR) if their zone is modeled separately, voiding the use of their historic capacity resources.
The solution approved by members makes three rule changes:
The PIRR is enforced only if the LDA has been separately modeled due to certain triggers;
An FRR Entity would be permitted to terminate its FRR alternative election prior to meeting the minimum five-year commitment period requirement under certain conditions; and
First-time elections of the FRR alternative would be due four months prior to a Base Residual Auction instead of the current two-month deadline.
PJM Asked to Consider Masking FTR Ownership
PJM would consider masking ownership of financial transmission rights under a problem statement presented by DC Energy’s Bruce Bleiweis at the MIC last week.
Currently, all RTOs publish the identities of FTR holders when posting auction results. By contrast, in all other market transactions, such as capacity auctions and daily energy auctions, PJM does not disclose the ownership, Bleiweis said.
“I think the inequity is transparent to everyone here,” Bleiweis said. “We don’t see any reason FTRs should be treated differently” than any other power product.
FERC initially allowed the current transparency to spur a secondary FTR market. Now that this market is established, this disclosure is no longer necessary, Bleiweis argued. He said that knowing another company’s position could lead to unfair competitive advantages.
There was some confusion as to what exactly is disclosed in other products, however. Carl Johnson of the PJM Public Power Coalition said he thought PJM published capacity positions of companies once the delivery year began.
PJM’s Tom Zadlo answered that only a list of cleared units is posted. Bleiweis said that if the problem statement is approved at next month’s MIC meeting, he would work with PJM to generate a simple list showing exactly what is posted for each product.
Marji Philips of Direct Energy said she “remains very concerned” by the proposal. In the past, she said, market participants have identified “mischief” in the FTR markets that the Independent Market Monitor and PJM did not catch, based on the increased transparency.
Bleiweis said PJM’s effort would be consistent with ISO-NE, which approved a move to aggregate FTR ownership at its November 2014 Markets Committee meeting.
The Nuclear Regulatory Commission has determined that NextEra Energy’s Seabrook Station could operate for another 20 years beyond 2030 without negative impact on the environment. NRC published its final report on the environmental impacts of renewing Seabrook’s operating license and gave the plant’s owners the green light to move to the next step in the re-licensing process.
“The NRC’s preliminary recommendation is that the adverse environmental impacts of license renewal for Seabrook are not great enough to deny the option of license renewal,” according to NRC, which based its findings on an environmental report submitted by NextEra Energy, consultation with federal, state and local agencies and NRC staff’s independent review and public comments.
A Safety Evaluation Report, the last step in the license renewal process, is scheduled for release in May. NextEra has been working through the renewal application since 2010.
Mass. Mayor to Ask FERC to Extend Meetings for Tennessee Gas Pipeline
The mayor of Peabody, Mass., wants FERC to add a special meeting near the city to allow the public to comment on Kinder Morgan’s plan to build a lateral from its Tennessee Gas Pipeline.
Mayor Ted Bettencourt said he would seek the additional meeting after he met with the Northeast Municipal Pipeline Coalition, a group opposing the pipeline. Kinder Morgan has said it wants to build the pipeline to provide fuel for power plants. The Northeast has experienced a shortage in natural gas during times of peak demand, such as frigid winter days and nights.
Several meetings have already been held concerning the pipeline, which is to run from Dracut, through Peabody and connect to an existing line in Danvers.
Ninth Circuit Throws out Suit Against FERC Curtailment Order
A panel of judges from the Ninth Circuit Court of Appeals has ruled that a group of wholesale electricity customers has no standing to sue FERC for requiring it to pay for curtailing wind generation in times of unusually high hydro generation.
The customers had argued that the dispatch-curtailment mandate — originally put into place as a result of high expected hydro generation on the Columbia River — meant that increased generation prices would be passed on to them. FERC issued the curtailment policy to cover incidents of “last resort” when high water levels forced Bonneville Power Administration to generate electricity that exceeded demand. In order to preserve system integrity, FERC decided it could mandate curtailment by other generators.
The plaintiffs argued that the mandate exceeded FERC’s area of responsibility, as it dealt with generation rather than transmission. The judges noted that the plaintiffs may suffer harm from the rule but that they had no statutory standing under FERC rules.
Report: Wind Could Replace Coal, Gas as Dominant Resources
The National Renewable Energy Laboratory released a report that shows that wind power’s capacity factor could reach 65%, exceeding both coal and natural gas.
The Department of Energy’s lab data indicates that increasing to a 65% capacity factor could reduce wind’s cost, improve transmission line efficiency and provide necessary power at times of peak demand. The report shows that if “near-term” technology and enough appropriate sites are used, the capacity factor of wind turbines could exceed both coal and natural gas. The report also indicated that new wind power technology on the horizon would mean that wind alone would be able to power the U.S. demand.
NRC: Beaver Valley Nuclear Station Has Enough Staff for Emergencies
The Nuclear Regulatory Commission has determined that the emergency plan of the Beaver Valley Nuclear Power Station in Pennsylvania is adequate to meet the needs for any large-scale emergencies. The commission reviewed the new safety guidelines put into place following the 2011 Fukushima nuclear disaster in Japan.
All of the nation’s nuclear stations are undergoing a commission review of plans updated after the disaster.
A report issued by the Nuclear Regulatory Commission found that a nuclear waste repository at Yucca Mountain would pose “only a negligible increase” in health risk from radioactivity leaking into groundwater. The study is one of the final products of the funding for the Yucca Mountain project, which President Obama mothballed in 2010.
The report will be presented next month in Washington and Nevada.
New Mexico Site Eyed for Storing Spent Nuclear Fuel
Holtec International has submitted documents showing its intent to file for a license to store spent nuclear fuel at a site in southeast New Mexico. The company said the facility would retain spent fuel from stations that are shutdown or in the process of decommissioning — Connecticut Yankee, Humboldt Bay, Kewaunee, La Crosse, Maine Yankee, Millstone Unit 1, Oyster Creek, Rancho Seco, Trojan, Yankee Rowe and Zion stations.
The letter of intent says that the site is 35 miles from any large population center. Holtec is asking the Nuclear Regulatory Commission for permission to store the fuel underground with the same system being used at Callaway and San Onofre stations.
Holtec said it is planning on filing its complete license application by June 2016.
NRC Dismisses Complaint Against San Onofre Station as Moot
The Nuclear Regulatory Commission has dismissed a complaint filed by an anti-nuclear organization against San Onofre nuclear generating station as moot because the station is being decommissioned. The Friends of the Earth filed the complaint against San Onofre owner Southern California Edison, alleging it failed to get approval for new steam generators before installing them.
The commission noted that fuel has been removed from the station and it is permanently closed, and so the complaint is unnecessary.
