U.S. electricity prices may be going up for good

By RALPH VARTABEDIAN

Los Angeles Times LOS ANGELES — As temperatures plunged to 16 below zero in Chicago in early January and set record lows across the eastern U.S., electrical system managers implored the public to turn off stoves, dryers and even lights or risk blackouts.

A fifth of all power-generating capacity in a grid serving 60 million people went suddenly offline, as coal piles froze, sensitive electrical equipment went haywire and utility operators had trouble finding enough natural gas to keep power plants running. The wholesale price of electricity skyrocketed to nearly $2 per kilowatt hour, more than 40 times the normal rate. The price hikes cascaded quickly down to consumers. Robert Thompson, who lives in the suburbs of Allentown, Pa., got a $1,250 bill for January.

 “I thought, how am I going to pay this?” he recalled. “This was going to put us in the poorhouse.”

The bill was reduced to about $750 after Thompson complained, but Susan Martucci, a part-time administrative assistant in Allentown, got no relief on her $654 charge. “It was ridiculous,” she said.

The electrical system’s duress was a direct result of the polar vortex, the cold air mass that settled over the nation. But it exposed a more fundamental problem. There is a growing fragility in the U.S. electricity system, experts warn, the result of the shutdown of coal-fired plants, reductions in nuclear power, a shift to more expensive renewable energy and natural gas pipeline constraints. The result is likely to be future price shocks. And they may not be temporary.

One recent study predicts the cost of electricity in California alone could jump 47 percent over the next 16 years, in part because of the state’s shift toward more expensive renewable energy.

“We are now in an era of rising electricity prices,” said Philip Moeller, a member of the Federal Energy Regulatory Commission, who said the steady reduction in generating capacity across the nation means that prices are headed up. “If you take enough supply out of the system, the price is going to increase."

In fact, the price of electricity has already been rising over the last decade, jumping by double digits in many states, even after accounting for inflation. In California, residential electricity prices shot up 30 percent between 2006 and 2012, adjusted for inflation, according to Energy Department figures. Experts in the state’s energy markets project the price could jump an additional 47 percent over the next 15 years.

The problems confronting the electricity system are the result of a wide range of forces: new federal regulations on toxic emissions, rules on greenhouse gases, state mandates for renewable power, technical problems at nuclear power plants and unpredictable price trends for natural gas.

 

Even cheap hydro power is declining in some areas, particularly California, owing to the long-lasting drought. “Everywhere you turn, there are proposals and regulations to make prices go higher,” said Daniel Kish, senior vice president at the Institute for Energy Research. “The trend line is up, up, up. We are going into uncharted territory.”

New emissions rules on mercury, acid gases and other toxics by the Environmental Protection Agency are expected to result in significant losses of the nation’s coal-generated power, historically the largest and cheapest source of electricity. Already, two dozen coal generating units across the country are scheduled for decommissioning. When the regulations go into effect next year, 60 gigawatts of capacity — equivalent to the output of 60 nuclear reactors — will be taken out of the system, according to Energy Department estimates.

Moeller, the federal energy commissioner, warns that these rapid changes are eroding the system’s ability to handle unexpected upsets, such as the polar vortex, and could result in brownouts or even blackouts in some regions as early as next year. He doesn’t argue against the changes, but believes they are being phased in too quickly.

The federal government appears to have underestimated the impact as well. An Environmental Protection Agency analysis in 2011 had asserted that new regulations would cause few coal plant retirements. The forecast on coal plants turned out wrong almost immediately, as utilities decided it wasn’t economical to upgrade their plants and scheduled them for decommissioning.

The lost coal-generating capacity is being replaced largely with cleaner natural gas, but the result is that electricity prices are linked to a fuel that has been far more volatile in price than coal. The price of natural gas now stands at about $4.50 per million BTUs, more expensive than coal. Plans to export massive amounts of liquefied natural gas, the rapid construction of gas-fired power plants and the growing trend to convert the U.S. heavy truck fleet to natural gas could exert even more upward pressure on prices. Malcolm Johnson, a former Shell Oil gas executive who now teaches the Oxford Princeton Program, a private energy training company, said prices could move toward European price levels of $10.

“When those natural gas prices start going up again, we will feel it in the way of higher electricity prices,” warns James Sweeney, a Stanford University energy expert.

The loss of coal is being exacerbated by problems at the nation’s nuclear plants. Five reactors have been taken out of operation in the last few years, mainly due to technical problems. Additional shutdowns are under consideration.

At the same time, 30 states have mandates for renewable energy that will require the use of more expensive wind and solar energy. Since those sources depend on the weather, they require backup generation — a hidden factor that can add significantly to the overall cost to consumers.

Unreviewed Safety Issue At Fitzpatrick?

April 30: Dummies using torus water to fill up the lines...but the senior resident and I think there is no big deal. The resident was a nice guy.

Unreviewed Safety Issue At Fitzpatrick

Imagine how dirty the water is? Why didn’t the clean CST water immediately flush out the dirty water?  It is not like the HPCI was circulating with dirty water for many minutes or hours clogging up the "enlarged" filter.

Can the dirty water clog up the containment stray?

How do they control torus sedimentation?

Why makes up the sedimentation?

How do you control the particle size?

You know the nature of sedimentation is rust and paint chips.

Is there some kind of microbe thing going on?

I called their Branch Chief and on site inspector office.

Any studies on how the sedimentation will interact with the cladding and fuel pins?

So what happens if HPCI was forced to use the torus instead of the preferred source?  

If that dirty water and you have to assume all the sedimentation gets mixed up completely in a accident...will we see any surprises when this dirty water get mixed up in a accident and gets injected into the core?

Where do they get the water to fill this guy? Some come from a demineralizer. Any carry over of the resins.

Any carry over from the originating source of water?

NRC INFORMATION NOTICE94-57: DEBRIS IN CONTAINMENT AND THE RESIDUAL HEAT REMOVAL SYSTEM

LER: 2012-002-01, High Pressure Coolant Injection System Pressure Control Valve Failure

According to the LER it is not sedimentation...it is debris that is clogging the filter.

"This change was made because of several instances where the 23PCV-50 filter or snubber would become blocked by debris thereby preventing the pressure control valve from controlling. A two year preventative maintenance (PM) activity was also established to clean, inspect, and replace the filter and snubber."

Why does the NRC shift from snubber to filter?

"23PCV-50 filter or snubber would become blocked by debris"

JAMES A. FITZPATRICK NUCLEARPOWER PLANT - NRC INTEGRATED INSPECTION REPORT 05000333/2014002

.1 (Closed) LERs 05000333/2012-002-00 and -01: High Pressure Coolant Injection

Pressure Control Valve Failure

On August 28, 2012, while operating the HPCI system for routine quarterly surveillance testing, operators identified that water was overflowing the ‘A’ reactor building equipment sump. Subsequent testing revealed that the source of this water had been the HPCI booster pump recirculation safety valve, 23SV-66, which was discharging 75 gallons per minute (gpm) to the equipment sump due to failure of the HPCI booster pump recirculation pressure control valve, 23PCV-50.

The HPCI system is normally aligned with pump suction from the CSTs. With 23PCV-50 failed, this would result in 75 gpm of CST water being rejected while HPCI was in operation, which would deplete the CST inventory more rapidly than would normally be expected to occur. FitzPatrick staff did not know if HPCI would be able to meet its mission time before automatically realigning to the suppression pool when the CST low level setpoint was reached. Operation of HPCI in this condition would be unacceptable because the rejection of 75 gpm of water from the suppression pool would exceed the 5 gpm limit for total leakage sources outside containment established by the UFSAR, and would be contrary to the requirement of TS 5.5.2 to minimize leakage from those portions of systems outside containment that could contain highly radioactive fluids during an accident to levels as low as practicable. Therefore, HPCI was declared inoperable on August 30, 2012. Revision 0 of the subject LER was submitted in accordance with 10 CFR 50.73(a)(2)(v)(D), “Any event or condition that could have prevented the fulfillment of the safety function of structures or systems that are needed to mitigate the consequences of an accident;” revision 1 was subsequently submitted to report a violation of TS in accordance with 10 CFR 50.73(a)(2)(i)(B).

Introduction. The inspectors identified a Green NCV of TS 3.5.1, “ECCS - Operating,” because filling the HPCI system with low quality water from the suppression pool following maintenance caused the HPCI booster pump recirculation pressure control valve, 23PCV-50, to fail, thereby making the HPCI system inoperable, and this condition existed for greater than the TS allowed outage time of 14 days. Although the HPCI system was inoperable, it still maintained its safety function to provide emergency core coolant flow in the event of an accident.

...Operating experience at FitzPatrick indicated that suppression pool water was not the preferable source for filling plant systems because it contains sediment from the suppression chamber (torus).

According to the LER it is not sedimentation...it is debris that is clogging the filter...

 

Natural Gas Implicated in Largest Bankruptcy Ever?

The NRC Keeps Watch Over Comanche Peak During Chapter 11 Proceedings

1 Comment Posted by Moderator on April 30, 2014

Lara Uselding

Region IV Public Affairs Officer

The owner/operator of the Comanche Peak nuclear power plant — Luminant Generation Company LLC – told us that its parent company, Energy Future Holdings (EFH), has filed for Chapter 11 bankruptcy. Chapter 11 provides time for a business to sort out its financial problems. 

 

This is not the first time an action like this has involved a nuclear plant. The owner of the Diablo Canyon plant went through a bankruptcy in 2001, and, in the 1980s, the Seabrook plant went through a similar process.

The NRC has been actively monitoring the situation since EFH told the Securities and Exchange Commission last year it may have difficulties meeting debt obligations. NRC staff has looked at any potential impacts on plant safety and security, the decommissioning fund, and the implementation of post-Fukushima action items. We determined the plant continues to be sufficiently funded...

Course, they own the two plant Commache Peak nuclear plant through Luminant.

I wonder are these plants comeptitive...who would buy them?

Big Texas Utility Files for Bankruptcy

By JULIE CRESWELL and MICHAEL J. DE LA MERCED

April 29, 2014, 7:15 am

Too big just failed.

The troubled Texas utility Energy Future Holdings – which, as TXU, was private equity’s biggest-ever buyout – filed for bankruptcy on Tuesday.

After months of on-again, off-again talks between the company, its owners and a dizzying hierarchy of creditors, the company went into Chapter 11 protection with a plan intended to stave off months of potentially rancorous fighting in court over pieces of the power company.

Energy Future will probably be split between its regulated electricity arm, Oncor, and its unregulated power-generation business. The talks had long been stymied by an array of issues, including whether such a split would create a tax bill of more than $7 billion.

Energy Future will become one of the biggest Chapter 11 filings in corporate history.

This is not the ending that the Wall Street private equity firms, including Kohlberg Kravis Roberts, TPG Capital and the private equity arm of Goldman Sachs, envisioned in 2007, when they acquired the TXU Corporation in a colossal $45 billion deal.

Their investments are expected to be all but be wiped out in the bankruptcy....

Massive New England Electric Market Manipulation

VY is making a killing in the market...what is the real reason they are shutting it down?

Brayton Point power plant owner denies market manipulation

By Erin Ailworth

Globe Staff April 28, 2014

The private equity firm that owns Brayton Point denied that it is closing the Somerset power plant to manipulate the New England electricity market and increase its profits by tens of millions of dollars, calling allegations by consumer advocates “baseless and uniformed.”

In a 14-page filing made Friday to federal regulators, Brayton Point LLC — which is owned by a subsidiary of the equity firm Energy Capital Partners of Short Hills, N.J. — defended Brayton Point’s planned retirement in 2017. The company said it made the decision after determining that continuing to operate the 53-year-old coal-fired plant in the face of cheap natural gas prices and increasing environmental regulations “would result in operating risks and losses.”

 “Brayton Point made an economically rational decision and believes that anyone in such a position would have done the same,” Brayton Point LLC said in its filing to the Federal Energy Regulatory Commission.

Several groups, led by the national consumer advocacy organization Public Citizen, have asked the FERC investigate Energy Capital Partners. They allege the firm decided to retire Brayton to push up payments to power generator by ISO New England, the grid operator, benefitting five other plants owned by Energy Capital Partners that sell into the New England market.

ISO New England pays power generator to commit to providing energy in future years so that the region has enough electricity to meet demand. ISO New England recently paid generators an estimated $1.4 billion for promising to provide electricity starting in mid-2017, the time at which Brayton Point is expected to shutter.

As a result, Public Citizen and others say, Energy Capital Partners reaped an extra $74 million for its other plants, in Dighton and Springfield, Dayville and Milford, Conn., and Albany, N.Y

Energy Capital Partners bought Brayton Point and two other power plants from their previous owner, Dominion, in 2013 for $472 million. Several weeks after closing the deal, the equity firm announced that it would retire the Somerset facility.

“We believe there was clear intent here of acquiring Brayton to manipulate the market,” said Tyson Slocum, director for Public Citizen’s energy program. ““They are telling us that five weeks after closing on a [multi-million dollar] acquisition that included three power plants, of which Brayton Point was one, they say, ‘Geez, we found out it’s not economical to run?’ That story on its face is laughable.”

In its filing, the owner of Brayton Point said the accusations leveled against it were made because certain parties are “unhappy with the level of clearing prices” recently paid by ISO New England to ensure power in 2017. Those prices were much higher than the prices ISO New England paid to ensure power in 2016.

“The Commission should refuse to entertain baseless allegations of market manipulation,” the firm wrote.

Representatives of ISO New England have declined to comment on the FERC case. In a press release February, ISO New England attributed the higher prices it paid were due to a shortfall of generating capacity needed for 2017.

The Federal Energy Regulatory Commission also has declined to comment on the case.

Extraordinary Profits Made at Vermont Yankee In Last Year.

Why are they shuttting down VY?   

 U.S. electricity prices maybe going up for good

The electrical system’s duress was a direct result of the polar vortex, the cold air mass that settled over the nation. But it exposed a more fundamental problem. There is a growing fragility in the U.S. electricity system, experts warn, the result of the shutdown of coal-fired plants, reductions in nuclear power, a shift to more expensive renewable energy and natural gas pipeline constraints. The result is likely to be future price shocks. And they may not be temporary. - See more at: http://columbiadailyherald.com/news/nation/us-electricity-prices-may-be-going-good#sthash.oAjV7rqM.dpuf

I”ve been saying this for the last month or so. I’ll bet you this past year per megawatt Vermont Yankee has been the most profitable nuclear plant in Entergy’s fleet.

I’ll bet you VY made the most money they even made this past year...

For the next decade, NEISO prices are supposed to skyrocket...

Poor regulatory oversight of natural gas...

FERC Commissioner Philip Moeller: Rolling Blackouts “Are aPossibility,” Thanks to EPA’s Utility MACT

VY has parting present for GMP:$17M

Terri Hallenbeck, Free Press Staff Writer 5:38 p.m. EDT April 25, 2014

MONTPELIER – It’s not every day you get a letter like Green Mountain Power Corp. received Thursday that’s actually not a scam.

“Please contact me at your earliest convenience to arrange receipt of the above referenced payment,” the letter from Entergy Vice President Marc Potkin ended. The above-referenced payment is for $17.8 million.

Green Mountain Power, the state’s largest utility, will receive much, if not all, that money from Entergy Corp., owner of the Vermont Yankee nuclear power plant, as part of a revenue-sharing agreement made during the 2002 sale of the plant to Entergy from the group of utilities that had owned the plant.

“It’s great news for our customers,” said Dorothy Schnure, spokeswoman for Green Mountain Power. “All the money we are entitled to will go to ratepayers.”

The money represents the first — and likely last — time the revenue-sharing has kicked in. Vermont Yankee is slated to close at the end of the year. Entergy announced last year that the plant was no longer economically viable to run.

The money comes as a result of unusually high market prices for nuclear power this past winter, said Chris Recchia, commissioner of the state Department of Public Service. Because Entergy is gearing up to close Vermont Yankee, the company was selling power on the open market rather than through contracts and benefited from the higher prices, he said.

Recchia said his department is looking into whether Green Mountain Power receives all the money or if there are other former owners of the plant that are eligible for some, a process he described as “complicated.” Two of the biggest former owners were Green Mountain Power and Central Vermont Public Service Corp., which has since merged with Green Mountain Power.

Whoever they end of being, the former owners are entitled to a total of $17,886,739.49, according to Potkin’s letter.

Under the revenue-sharing agreement, if Vermont Yankee extended its operating license beyond 2012, the former owners would receive 50 percent of any revenue from power sold for more than $61 per megawatt for 10 years. Vermont Yankee has continued operating beyond 2012, even as the state tried to shut the plant down and the plant technically lacked a state certificate of public good until this year.

The $17.8 million Entergy is sharing represents the “excess revenue”Vermont Yankee earned from March 13, 2013, to March 12, 2014, Potkin said in the letter to Green Mountain Power. Nuclear power prices were too low for there to be any revenue sharing the year before, so this constitutes the first time the agreement has kicked in, Recchia said.

When state officials were arguing in recent years that Vermont Yankee should not be granted a 20-year license extension, one of their arguments that the extension was not in the public’s interest was that they doubted prices would ever be high enough for Vermont utilities to receive any revenue sharing before the agreement ended in 2020.

How we got here with our electric system...

For a reasonable price, we need a regulated electric utility or, better still, power generated through a government-owned authority

To the Editor:

This winter, National Grid ratepayers were subjected to exorbitant electric bills, which have been attributed to the high cost of natural gas. Although some commentators have inquired as to why natural gas prices were so high, there is a more basic question: Why did New York State, and National Grid customers in particular, become so dependent on natural gas in the first place?

The answer to that question lies in the decision made by the Public Service Commission to deregulate or “restructure” the electric industry in the 1990s, a decision that resulted in significant financial windfalls for large industrial users; National Grid’s predecessor, Niagara Mohawk; and for power plant developers, but was a total disaster for the residential ratepayers of New York State.

When electric power was first developed, in the late 19th and early 20th centuries, it was not practicable to have competing electric companies because only one central station and only one set of wires was needed in a particular urban area.

Rather than establish municipally owned power systems, most states in the United States adopted a model of a “regulated utility” for electric power. Under this model, a monopoly would be granted to a private company, which would be guaranteed a profit.

The concept of a “regulated utility” was championed by Samuel Insull, who came to the United States in 1879 to work as Thomas Edison’s personal secretary and was instrumental in bringing General Electric to Schenectady. Insull left General Electric in 1892 to develop one of the first central electric stations in Chicago.

Although Insull advocated for government ownership of the electric industry in his native England, he worked with a variety of industrial interests to develop the concept of an electric monopoly, with rates to be set by government regulators, as an alternative to the “socialist” government ownership.

Electric power rates were designed to reimburse operating costs, and to provide a profit on capital investment. Therefore, electric utilities were encouraged to build capital-intensive power plants, rather than plants with low capital investment and relatively high operating costs.

Utilities, including Niagara Mohawk, primarily relied on large oil, coal, and later nuclear plants, which were expensive to construct, but, once constructed, generated large quantities of power at relatively low average cost.

In the early 1990s, largely as a result of the Federal Energy Regulatory Commission’s Order 888, electric transmission facilities were opened up to competition, which made it possible for electric users, especially large industrial users, to buy power from other generators besides their local electric utility. Many states, including New York, decided to “deregulate” or “restructure” their electric utilities, based upon a mystical belief that the market would solve all problems, and the cost of electricity would decrease.

In reality, the only electrical consumers to benefit were the large industrial users.

Under deregulation, Niagara Mohawk was required to divest itself of all of its power plants, including the large “base-load” plants that generated electric power cheaply, and purchase power on the open market, for resale to its remaining customers. Because of the particularly shameful way that the Public Service Commission chose to implement deregulation, Niagara Mohawk recovered the costs of its wasteful construction practices at the nuclear plant Nine Mile 2 and sold its generating power plants at highly discounted prices and stuck ratepayers with the costs through a “competitive transition charge.”

Advocates of unrestricted competition claimed that Niagara Mohawk would be able to purchase cheaper power because the owners of merchant power plants would compete against each other to sell power. However, the new owners of Niagara Mohawk’s large plants frequently chose to sell power directly to large industrial users, rather than sell to Niagara Mohawk for delivery to residential users.

More critically, no new large plants with low average costs for electricity have been built in New York in recent years.

Power producers chose to construct natural gas electrical generating plants — even though they generate higher cost power — because they come on line much more quickly than oil or coal or nuclear plants.

The price of electric power is determined in a complicated bidding system, by which generators offer to sell power, both on a long-term basis and for very short periods of time. The need for power, and therefore the price, is greatest during times of peak demand, typically periods of extreme cold or extreme heat.

More profit can be made by constructing plants that can sell power during peak events at a higher price, than can be made constructing the base-load plants that are actually needed.
Therefore, power producers have chosen to focus on building more natural gas plants, which, while providing a greater profit margin for the power producer, do not meet the needs of New York State residents.

Almost 20 years after the decision was made to deregulate the electric industry, National Grid customers are increasingly dependent upon high-cost natural gas plants, which can become even more high-cost when, as happened this winter, gas prices spike.

The only way of assuring reliable electric service for New York State residents at a reasonable price is to attempt to put the genie back in the bottle: to re-establish a regulated electric utility or, even better, have power delivered through a government-owned authority.
The crisis this winter should demonstrate what should have been obvious 15 years ago: The vagaries of the market cannot adequately handle the provision of a fundamental service such as electricity.

Peter Henner
New Scotland

Editor’s note: Peter Henner, who writes the Enterprise chess column, is a lawyer. In 1998, he represented several municipalities, including the cities of Oswego and Cohoes, in a legal challenge to the restructuring of Niagara Mohawk in 1998. In 2002 and 2003, he taught a graduate course in the Rensselaer Polytechnic Institute’s Environmental Management program on the restructuring of the electric industry.

Post date:

April 23, 2014

Please reform the NRC 2.206 process

 

The agency is a friend of obfuscation even fro within:

OIG notes that NRC management has accepted, but uses conditional language to articulate, the actions planned. This obfuscates the agency’s intentions with regard to the recommendations.

You notice they release the letter after the 2.206 meeting.

April 14, 2014

Michael Mulligan
P.O. Box 161
Hinsdale, NH 03451

Dear Mr. Mulligan:

On behalf of the U.S. Nuclear Regulatory Commission (NRC), I am responding to your email dated March 11, 2014 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML14076A060) to Chairman Macfarlane. Your letter was referred to me for reply. In your email, you expressed several concerns regarding the transparency of the NRC’s Title 10 Code of Federal Regulations (10 CFR), Part 2, Section 2.206 process (herein referred to as the 2.206 process). To summarize your concerns you requested that:

1. A NRC senior executive be assigned to help you navigate the NRC’s 2.206 process to
ensure openness, similar to the role of an ombudsman.

2. NRC employees be punished if they mislead a petitioner or withhold information from
inside the process, and that licensees should be held accountable by the NRC to answer your questions.

3. Petition review board (PRB) internal meetings should be open meetings that the public can observe.

4. The 2.206 process should be completely overhauled.

Thank you for sharing your concerns and recommendations.

Before I address each of your concerns, I would like to emphasize that the 2.206 process is

Wouldn't it be great if we knew what caused the 2.206 process to be brought into being.

 

unique to the NRC. It is our goal to ensure open, transparent communications with the public during this process. Under the 2.206 process, any member of the public can petition the NRC to take enforcement action against an NRC licensee. The NRC staff’s guidance for the disposition of 2.206 petition requests is in Management Directive (MD) 8.11, “Review Process for 10 CFR 2.206 Petitions,” which is publicly available in ADAMS (Accession No.ML041770328).

Regarding your first concern, in lieu of an ombudsman, all 2.206 petitioners are provided with a NRC petition manager. The petition manager is generally a seasoned staff member

They know what i am talking about...the petition manage has two hats on. One giant hat that serves the agency and the licence and a itty bitty hat on that serves me. Right a employee who serves me and he is involve in getting me the information I want, not just within the 2.206 process. I got to be honest, the agency has given me unprecedented access to the inspector staff at Palisades. But again these employees serve the agency.

who is knowledgeable of the 2.206 process. In addition, a coordinator is involved in the review of every 2.206 petition, to ensure that the PRB members are implementing MD 8.11 as required. The coordinator is also available to address any concerns or questions that a petitioner may have on the process. Finally, each 2.206 petition is led by a senior level executive who serves as the PRB chairperson. If you have any concerns about the openness of the 2.206 process during the review of your 2.206 petition, please express any specific concerns with the PRB chairperson.

Regarding your second concern, you did not provide any examples in your email; however, if you have any specific concerns about information being withheld or NRC staff misleading a petitioner, please promptly advise the PRB chairperson for your 2.206 petition. The PRB chairperson ensures that these matters are referred to the Office of the Inspector General (OIG), the Office of Investigations, or the Office Allegations Coordinator as appropriate. In addition, independent of the PRB, you can also submit any concerns that you have directly to the NRC’s OIG Hotline (1-800-233-3497).

Regarding your third concern, although the 2.206 process allows for more public participation than other NRC processes, it does not afford the public with the opportunity to observe he PRB closed meeting. This closed meeting supports the NRC staff’s ability to have an open dialogue with its technical experts and senior management to discuss the facts provided on each petition and to evaluate the petition against the criteria for review and rejection. The PRB often discusses pre-decisional (i.e., privileged) information related to inspections or investigations if this information is relevant to its review of the 2.206 petition. In order to preserve those privileges, the PRB meetings are not recorded and are closed to the public. Therefore, the PRB closed meeting would not be recorded and posted to the NRC’s public website, as you recommend. It is the petition manager’s responsibility to convey the outcome of the PRB’s internal meetings to the petitioner and to ensure that the petitioner is provided with opportunities to address the PRB if clarifications or additional information are warranted.

Regarding your final request for the NRC to overhaul the 2.206 process, I’d like to make you aware that a Federal Register notice (FRN) was issued on July 30, 2010, to inform members of the public about the NRC’s plans to revise MD 8.11. The FRN also requested comments from members of the public since the 10 CFR 2.206 process is a public process. All external comments received are currently being considered by the NRC to support a revision to MD 8.11. Although the public comment period has expired, the staff will consider your comments, which are similar to those already received by other members of the public, to glean any new insights to enhance transparency in the 2.206 process.

On behalf of the NRC, I appreciate your time and attention in reaching out to share your views on this matter.

Sincerely,

/RA?Jennifer L. Uhle, Deputy Director
for Reactor Safety Programs
Office of Nuclear Reactor Regulation

"Foreign material" on the brain and risk perspective

 

“Foreign materials” on the brain and Nuclear industry risk perspective.

Do we really know the risk in a nuclear plant?

So what does “safety related” mean. I don’t think there has been net increase in safety coming from the responses of Fukushima; gear, procedures, pumps and diesel generators. They are just moving safety from one category to another. As example, they are justifying more unsafety like in violating regulatory or licensing bases rules in the Palisades PCP (flung off impeller blades) continuing event based on fixing or mitigating the shortcomings of the USA’s Fukushima SBO issues. Those pumps are unfit for use in a nuclear power plant primary system (poorly designed) and Palisades have had a host of serious problems with these pumps beginning in 1971 according to the NRC.

There has been and continues to be a secret massive and increasing acceptance of plant centric risk in a tradeoff of reducing risk in a Fukushima style USA SBO event. We are trading electrical reliability safety in a highly improbable accident in a beyond a design accident for less safety in plant components and system degradations on a daily or very frequent bases. This is vastly kicking up capacity factor or obscuring a decline in plant reliability and safety. It is mostly the stuff we can’t see or measure while up at power. Most plants are probably making a lot of money over this or obscuring the detection of decline in competence with operating a nuclear power plant.

Something bad going to is happen if we globally “normalize the deviance” on safety degradation through an accepted bureaucratic process (risk perspectives) like in the Palisades PCP impeller problem. A known, unknown and not measure risk unsafety could coagulate into an imaginable accident like the red finding like in ANO and Browns Ferry.

What if, say in 10,000 components or safety systems, we collectively reduce USA fleet wide safety, tolerate more degradations or accept a reduction in component reliability wholly based or keyed off a distance and improbable increase of safety in a beyond a design event. Instead of talking about isolated plant inncidents, we are talking about global or US flleet wide safety...changing the regulatory safety philosophy USA fleet wide. The tiny increase in “improbably used” safety and the massive increase in regularly “used unsafety” are so disproportional. An infrequent and improbable single aspect of a plant can influence so many other frequent and simultaneous probable aspects of a plant. Your get it, through the Fukushima responses and the beyond the plant design accident new components; you could justify the degradation of safety in say 100 components simultaneously. It can mitigate the threat of a shutdown caused by degraded components and it can mitigate size of a NRC violation at the same time. It could be a one to a thousand relationship or more with an increased in improbable  safety by adding safety components in beyond plant design accident to actual unsafety by tolerating degraded component in a safety system, tolerating a violation plant licensing and NRC violations But you will probably never consume the increased in the public safety through the beyond the plant design accident safety or mitigation components by the ongoing degradation in on going components and rules violations.

And remember, we have little idea what the total level of component degradation, failure to obey NRC regulations or to stay within plant designs and licensing rules. The licensee doesn’t disclose and the NRC captures only a very small percentage of these. If we unjustly increase on a US fleet wide bases the risk profile in the nuclear plant centric systems we are heading for big trouble!

Risk perspectives is like complexity on steroids and heroin in our aging fleet of nuclear plants. It is collectively and increasingly blinding us. It is not shining light and understanding on problems in the industry....it is enabling and prolonging problems in our USA fleet. It is nothing to do with a fix it first and early philosophy!

Supplement to Palisades Defective PCP Pumps 2.206

 

The problem here is the licensee and NRC didn’t think a USFAR, licensing and other requirement violations were a substantial safety hazard either on the pump or repetitively spewing blade fragments all over in the coolant. They weren’t forced to justify it publicly...

 SUBJECT: STATUS OFRECOMMENDATIONS: AUDIT OF NRC’S IMPLEMENTATION OF 10 CFR PART 21, REPORTING OFDEFECTS AND NONCOMPLIANCE (OIG-11-A-08)

Attached is the Office of the Inspector General’s analysis and status of recommendations 1, 2, 3, 4, and 5 as discussed in the agency’s response dated

April 27, 2011. Based on OIG’s analysis of this response, recommendations 1, 3, and 5 are unresolved and recommendations 2 and 4 are resolved.

OIG notes that NRC management has accepted, but uses conditional language to articulate, the actions planned. This obfuscates the agency’s intentions with regard to the recommendations. It is paramount for OIG to have a clear understanding of the NRC management position with regard to reportability under Part 21. Recent manufacturing defects at two separate nuclear power plants illustrate why this is important.

One nuclear power plant recently received a Red finding under NRC’s Reactor Oversight Program because a safety-related coolant injection valve was discovered to have been broken and unable to perform its safety function for an extended period of time. Had this same valve been out of service for less than 7 days, the failure of the valve would not have been reportable under Part 21 according to some interpretations because it would not have met Part 50 event reporting requirements, and the nuclear industry would not have been informed of a manufacturing defect in a safety-related component.

At another nuclear power plant, the licensee discovered that a safety-related part necessary to operate a circuit breaker had a manufacturing defect that would prevent the breaker from performing its safety function. Some of the breakers were installed in the plant and some were on the shelf in the plant’s warehouse. Under the interpretation of some in industry and at NRC, the failure of the part installed in the operating nuclear plant would not be reportable under Part 21 because the failure did not meet Part 50 event reporting requirements, but the same defective part, if in the warehouse, would be reportable under Part 21.

Until NRC makes a final determination as to whether Part 21 defect reporting should be required separate from Part 50 event reporting requirements, some licensees and NRC staff will continue to assume that Part 21 evaluation and reporting is not necessary at operating nuclear power plants unless the defect causes an event. Accordingly, please provide the proposed corrective action for the unresolved recommendations and an updated status of the resolved recommendations by August 20, 2011. If you have any questions or concerns, please call me at 415-5915 or R.K. Wild, at 415-5948.

...The response states that it agrees that Part 21 and associated staff guidance are open to interpretation. The fact that NRC staff and licensees have varying interpretations of Part 21 reporting requirements is the problem OIG identified in the subject report.

...Does not clearly indicate that the staff will propose clarification so that Part 21 is in full conformity with Energy Reorganization Act of 1974, As Amended, Section 206, Noncompliance, with regard to industry’s obligation to report to NRC defects in basic components that could cause a substantial safety hazard.

... Substantial safety hazard means a loss of safety function to the extent that there is a major reduction in the degree of protection provided to public health and safety for any facility or activity licensed or otherwise approved or regulated by the NRC, other than for export, under parts 30, 40, 50, 52, 60, 61, 63, 70, 71, or 72 of this chapter.

So the above picture are examples of cavitations. Remember a 5 by 12 inch loose blade in Palisades. They only talk about pieces broken...they never talk about how worn the rest of the blades are.

April 10:

Basically controlling the sequencing of the PCP means they start the impellers who are weld free before the impeller who have been welded!

On the Oct, 1211 Palisades had a incident where one of their PCP pump broke off a impeller blade. They continued operating the plant for about 10 months...then went into outage. They did a simple search for the blade...couldn’t find it. IR 2012003 detailed the event. The outage occurred between April 9 and May 12, 2012. IR 2012003 was written up post this outage. During the Palisades 2014 outage, this is when they found the Oct, 2011 broken blade when they did a ten year inspection of core components...they removed components from the core gaining the ability to see this stuck blade.

I consider the NRC not mentioning Palisades couldn’t find the broken blade constitutes a cover-up in IR 2012003. The NRC should have given outsiders opportunity to make comment or inter into a process like a 2.206. The NRC secrecy impeded my ability to interact in an agency process with a dangerous and untrustworthy nuclear poor staff.

In the direct vicinity of the Oct 11 broken blade event Palisades was starting up from the yellow finding  DC bus breaker short and this placed employees in serious risk of death. There weren’t following their procedures...the procedure if followed won’t have worked. During that time they were dealing with multiple shutdowns with the leaking safety injection/refueling water tank and six shutdowns for a host of other reasons. Palisades with their operations and shutdown was considered one the most economically vulnerable plant is the USA. I think the NRC secrecy with not disclosing the unrecoverable blade and forcing the staff to do a ten year style inspection of the reactor internals to find broken blade was intended by the NRC to protect Entergy and Palisades from millions of dollars of expenses and extending the outage for days.

As I spoke about yesterday, I believe the agency sets these events up to be not scutinizable. Outsiders weren’t notified of the Oct 11 broken bladed until about 10 months after the event and on south side of the outage. In the post outage inspection report, the agency never admitted the licensee couldn’t find the broken. The NRC gave “secret” permission to start up the plant without finding the Oct 11 5 inch by 12 inch broken blade and yanking it out of the core. This plant has a long history of finding broken in their system and not repairing the degraded pump.

Further, I can name a 2007 incident where pieces of blades were found in the core. It sounds like finding PCP blade pieces in the core is a frequent experience. Then the Palisades staff played Abbot and Costello’s ‘Who’s one First’ on what PCP pump did the discovered in the core broken blade come from. They stated up the plant with a pump and pumps missing blades and degraded PCP pumps.        

I consider the free floating 5 by 12 inch broken blade post Oct 11 a direct threat to a very serious partial core meltdown. This is the event that remained unscrutinizable to outsiders for 11 mouths...where the agency hid that the blade could not be found and gave secret permission to restate the plant in a dangerous condition.  I contend that plant should have been shut down shortly after Oct 11 to replace the defective impeller with a missing 5 inch by 12 inch blade and inspect all the other impellers for cracks. The NRC should have forced the staff to find and remove the missing blade up and including a ten year style core internal inspection. I know it would have been very expensive...that is why a staff should preclude the possibility of broken PCP blades and degraded pumps. I am convinced if they would have found the blade in the current stuck position between the vessel and the flow shirt shorty after Oct 11it could have been easily removed. I am convinced 11 month later in the April 2012 outage if the NRC would have forced the Palisades staff to find the Oct 2011 blade it would have been removable. I’d like to see the Palisades internal report and analysis near the May 12, 2012 startup, where Palisades thought the broken 5 inch by 12 inch laid in the plant. It doesn’t take a PhD to figure it was somewhere near its current location....they knew it was there.

Right, again the agency sets this up to be unscrutinizable...all the information hidden...until after the bulk of the operation threat is long gone past a possibility. The outage is long gone by and the agency now analyses what they feel what will make them gone. You get what I am talking about...the NRC makes Palisades unscutinizable to outsiders. The big picture here is the agency is making themselves and congressional oversight unscutinable to outsiders. The NRC gets to pick the selective happy news to the outsiders making government unaccountable to the voters!