Nuclear Safety Culture and the Shrinking U.S. Nuclear Plant Population

In the last few years, nuclear plant owners have shut down or scheduled for shutdown 17 units totaling over 14,000 MW.  Over half of these units had (or have) nuclear safety culture (NSC) issues sufficiently noteworthy to warrant mention here on Safetymatters.  We are not saying that NSC issues alone have led to the permanent shutdown of any plant, but such issues often accompany poor decision-making that can hasten a plant’s demise.  Following is a roll call of the deceased or endangered plants.

Plants with NSC issues

NSC issues provide windows into organizational behavior; the sizes of issues range from isolated problems to systemic weaknesses.

FitzPatrick

This one doesn’t exactly belong on the list.  Entergy scheduled it for shutdown in Jan. 2017 but instead it will likely be purchased by a white knight, Exelon, in a transaction brokered by the governor of New York.  With respect to NSC, in 2012 FitzPatrick received a Confirmatory Order (CO) after the NRC discovered violations, the majority of which were willful, related to adherence to site radiation protection procedures. 

Fort Calhoun

This plant shut down on Oct. 24, 2016.  According to the owner, the reason was “market conditions.”  It’s hard for a plant to be economically viable when it was shut down for over two years because of scheduled maintenance, flooding, a fire and various safety violations.  The plant kept moving down the NRC Action Matrix which meant more inspections and a third-party NSC assessment.  A serious cultural issue was how the plant staff’s perception of the Corrective Action Program (CAP) had evolved to view the CAP as a work management system rather than the principal way for the plant to identify and fix its problems.  Click on the Fort Calhoun label to pull up our related posts.

Indian Point 2 and 3

Units 2 and 3 are scheduled to shut down in 2020 and 2021, respectively.  As the surrounding population grew, the political pressure to shut them down also increased.  A long history of technical and regulatory issues did not inspire confidence.  In NSC space, they had problems with making incomplete or false statements to the NRC, a cardinal sin for a regulated entity.  The plant received a Notice of Violation (NOV) in 2015 for providing information about a licensed operator's medical condition that was not complete and accurate; they received a NOV in 2014 because a chemistry manager falsified test results.  Our May 12, 2014 post on the latter event is a reader favorite. 

Palisades

This plant had a long history of technical and NSC issues.  It is scheduled for shutdown on Oct. 1, 2018.  In 2015 Palisades received a NOV because it provided information to the NRC that was not complete and accurate; in 2014 it received a CO because a security manager assigned a person to a role for which he was not qualified; in 2012 it received a CO after an operator left the control room without permission and without performing a turnover to another operator.  Click on the Palisades label to pull up our related posts.

Pilgrim

This plant is scheduled for shutdown on May 31, 2019.  It worked its way to column 4 of the Action Matrix in Sept. 2015 and is currently undergoing an IP 95003 inspection, including an in-depth evaluation of the plant’s CAP and an independent assessment of the plant’s NSC.  In 2013, Pilgrim received a NOV because it provided information to the NRC that was not complete and accurate; in 2005 it received a NOV after an on-duty supervisor was observed sleeping in the control room.

San Onofre 2 and 3

These units ceased operations on Jan. 1, 2012.  The proximate cause of death was management incompetence: management opted to replace the old steam generators (S/Gs) with a large, complex design that the vendor had never fabricated before.  The new S/Gs were unacceptable in operation when tube leakage occurred due to excessive vibrations.  NSC was never anything to write home about either: the plant was plagued for years by incidents, including willful violations, and employees claiming they feared retaliation if they reported or discussed such incidents.

Vermont Yankee

This plant shut down on Dec. 29, 2014 ostensibly for “economic reasons” but it had a vociferous group of critics calling for it to go.  The plant evidenced a significant NSC issue in 2009 when plant staff parsed an information request to the point where they made statements that were “incomplete and misleading” to state regulators about tritium leakage from plant piping.  Eleven employees, including the VP for operations, were subsequently put on leave or reprimanded.  Click on the Vermont Yankee label to pull up our related posts.

Plant with no serious or interesting NSC issues 

The following plants have not appeared on our NSC radar in the eight years we’ve been publishing Safetymatters.  We have singled out a couple of them for extremely poor management decisions.

Crystal River basically committed suicide when they tried to create a major containment penetration on their own and ended up with a delaminating containment.  It ceased operations on Sept. 26, 2009.

Kewaunee shut down on May 7, 2013 for economic reasons, viz., the plant owner apparently believed their initial 8-year PPA would be followed by equal or even higher prices in the electricity market.  The owner was wrong.

Rounding out the list, Clinton is scheduled to shut down June 1, 2017; Diablo Canyon 1 and 2 will shut down in 2024 and 2025, respectively; Oyster Creek is scheduled to shut down on June 1, 2019; and Quad Cities 1 and 2 are scheduled to shut down on June 1, 2018 — all for business reasons.

Our Perspective

Bad economics (low natural gas prices, no economies of scale for small units) were the key drivers of these shutdown decisions but NSC issues and management incompetence played important supporting roles.  NSC problems provide ammunition to zealous plant critics but, more importantly, also create questions about plant safety and viability in the minds of the larger public.

The Incredible Shrinking Nuclear Industry

News last week that the San Onofre units would permanently shutdown - joining Crystal River 3 (CR3) and Kewaunee as the latest early retirees - and filling in the last leg of a nuclear bad news trifecta.  This is distressing on many fronts, not the least of which is the loss of jobs for thousands of highly qualified nuclear personnel, and perhaps the suggestion of a larger trend.  Almost as distressing is the characterization by NEI that San Onofre is a unique situation - as were CR3 and Kewaunee by the way - and placing primary blame on the NRC.*  Really?  The more useful question to ponder is what decisions led up to the need for plant closures and whether there is a common denominator? 

We can think of one: decisions that failed to adequately account for the “tail” of the risk distribution where outcomes, albeit of low probability, carry high consequences.  On this score checking in with Nick Taleb is always instructive.  He observes “This idea that in order to make a decision you need to focus on the consequences (which you can know) rather than the probability (which you can’t know) is the central idea of uncertainty.”**

• For Kewaunee the decision to purchase the plant with a power purchase agreement (PPA) that extended only for eight years;
• For CR3, the decision to undertake cutting the containment with in-house expertise;
• For SONGs the decision to purchase and install new design steam generators from a vendor working beyond its historical experience envelope.

Whether the decision makers understood this, or even imagined that their decisions included the potential to lose the plants, the results speak for themselves.  These people were in Black Swan and fat tail territory and didn’t realize it.  Let’s look at a few details.

Kewaunee

Many commentators at this point are writing off the Kewaunee retirement based on the miracle of low gas prices.  Dominion cites gas prices and the inability to acquire additional nuclear units in the upper Midwest to achieve economies of scale.  But there is a far greater misstep in the story.  When Dominion purchased Kewaunee from Wisconsin Public Service in 2005, a PPA was included as part of the transaction.  This is an expected and necessary part of the transaction as it established set prices for the sale of the plant’s output for a period of time.  A key consideration in structuring deals such as this is not only the specific pricing terms for the asset and the PPA, but the duration of the PPA.  In the case of Kewaunee the PPA ran for only 8 years, through December 2013.  After 8 years Dominion would have to negotiate another PPA with the local utilities or others or sell into the market.  The question is - when buying an asset with a useful life of 28 years (with grant of the 20 year license extension), why would Dominion be OK with just an 8 year PPA?  Perhaps Dominion assumed that market prices would be higher in 8 years and wanted to capitalize on those higher prices.  Opponents to the transaction believed this to be the case.***  The prevailing expectation at the time was that demand would continue along with appropriate pricing necessary to accommodate current and planned generating units.  But the economic downturn capped demand and left a surplus of baseload.  Local utilities faced with the option of negotiating a PPA for Kewaunee - or thinning the field and protecting their own assets - did what was in their interest. 

The reality is that Dominion rolled the dice on future power prices.  Interestingly, in the same time frame, 2007, the Point Beach units were purchased by NextEra Energy Resources (formerly FPL Energy).  In this transaction PPAs were negotiated through the end of the extended license terms of the units, 2030 and 2033, providing the basis for a continuing and productive future.

Crystal River 3

In 2009 Progress Energy undertook a project to replace the steam generators in CR3.  As with some other nuclear plants this necessitated cutting into the containment to allow removal of the old generators and placement of the new. 

Apparently just two companies, Bechtel and SGT, had managed all the previous 34 steam generator replacement projects at U.S. nuclear power plants. Of those, at least 13 had involved cutting into the containment building. All 34 projects were successful.

For the management portion of the job, Progress got bids from both Bechtel and SGT. The lowest was from SGT but Progress opted to self-manage the project to save an estimated $15 million.  During the containment cutting process delamination of concrete occurred in several places.  Subsequently an outside engineering firm hired to do the failure analysis stated that cutting the steel tensioning bands in the sequence done by Progress Energy along with removing of the concrete had caused the containment building to crack.  Progress Energy disagreed stating the cracks “could not have been predicted”.  (See Taleb’s view on uncertainty above.)

“Last year, the PSC endorsed a settlement agreement that let Progress Energy refund $288 million to customers in exchange for ending a public investigation of how the utility broke the nuclear plant.”****

When it came time to assess how to fix the damage, Progress Energy took a far more conservative and comprehensive approach.  They engaged multiple outside consultants and evaluated numerous possible repair options.  After Duke Energy acquired Progress, Duke engaged an independent, third-party review of the engineering and construction plan developed by Progress.  The independent review suggested that the cost was likely to be almost $1.5 billion. However, in the worst-case scenario, it could cost almost $3.5 billion and take eight years to complete.   “...the [independent consultant] report concluded that the current repair plan ‘appears to be technically feasible, but significant risks and technical issues still need to be resolved, including the ultimate scope of any repair work.’"*****  Ultimately consideration of the potentially huge cost and schedule consequences caused Duke to pull the plug.  Taleb would approve.

San Onofre

Southern California Edison undertook a project to replace its steam generators almost 10 years ago.  It decided to contract with Mitsubishi Heavy Industries (MHI) to design and construct the generators.  This would be new territory for Mitsubishi in terms of the size of the generators and design complexity.  Following installation and operation for a period of time, tube leakage occurred due to excessive vibrations.  The NRC determined that the problems in the steam generators were associated with errors in MHI's computer modeling, which led to underestimation of thermal hydraulic conditions in the generators.

“Success in developing a new and larger steam generator design requires a full understanding of the risks inherent in this process and putting in place measures to manage these risks….Based upon these observations, I am concerned that there is the potential that design flaws could be inadvertently introduced into the steam generator design that will lead to unacceptable consequences (e.g., tube wear and eventually tube plugging). This would be a disastrous outcome for both of us and a result each of our companies desire to avoid. In evaluating this concern, it would appear that one way to avoid this outcome is to ensure that relevant experience in designing larger sized steam generators be utilized. It is my understanding the Mitsubishi Heavy Industries is considering the use of Westinghouse in several areas related to scaling up of your current steam generator design (as noted above). I applaud your effort in this regard and endorse your attempt to draw upon the expertise of other individuals and company's to improve the likelihood of a successful outcome for this project.”#

Unfortunately these concerns raised by SCE came after letting the contract to Mitsubishi.  SCE placed (all of) its hopes on improving the likelihood of a successful outcome at the same time stating that a design flaw would be “disastrous”.  They were right about the disaster part.

Take Away

These are cautionary tales on a significant scale.  Delving into how such high risk (technical and financial) decisions were made and turned out so badly could provide useful lessons learned.  That doesn’t appear likely given the interests of the parties and being inconsistent with the industry predicate of operational excellence.

With regard to our subject of interest, safety culture, the dynamics of safety decisions are subject to similar issues and bear directly on safety outcomes.  Recall that in our recent posts on implementing safety culture policy, we proposed a scoring system for decisions that includes the safety significance and uncertainty associated with the issue under consideration.  The analog to Taleb’s “central idea of uncertainty” is intentional and necessary.  Taleb argues you can’t know the probability of consequences.  We don’t disagree but as a “known unknown” we think it is useful for decision makers to recognize how uncertain the significance (consequences) may be and calibrate their decision accordingly.


*  “Of course, it’s regrettable...Crystal River is closing, the reasons are easy to grasp, and they are unique to the plant. Even San Onofre, which has also been closed for technical reasons (steam generator problems there), is quite different in specifics and probable outcome. So – unfortunate, yes; a dire pox upon the industry, not so much.”  M. Flanagan, "Crystal River: End Days of Nuclear Energy?" NEI Nuclear Notes (Feb. 7, 2013).  Retrieved June 17, 2013.  For the NEI/SCE perspective on regulatory foot-dragging and uncertainty, see W. Freebairn et al, "SoCal Ed to retire San Onofre nuclear units, blames NRC delays," Platts (June 7, 2013).  Retrieved June 17, 2013.  And "NEI's Peterson discusses politics surrounding NRC confirmation, San Onofre closure," Environment & Energy Publishing OnPoint (June 17, 2013).  Retrieved June 17, 2013.

**  N. Taleb, The Black Swan (New York: Random House, 2007), p. 211.  See also our post on Taleb dated Nov. 9, 2011.

***  The Customers First coalition that opposed the sale of the plant in 2004 argued: “Until 2013, a complex purchased-power agreement subject to federal jurisdiction will replace PSCW review. After 2013, the plant’s output will be sold at prices that are likely to substantially exceed cost.”  Customers First!, "Statement of Position: Proposed Sale of the Kewaunee Nuclear Power Plant April 2004" (April, 2004).  Retrieved June 17, 2013.

****  R. Trigaux, "Who's to blame for the early demise of Crystal River nuclear power plant?" Tampa Bay Times (Feb. 5, 2013).  Retrieved Jun 17, 2013.  We posted on CR3's blunder and unfolding financial mess on Nov. 11, 2011.

*****  "Costly estimates for Crystal River repairs," World Nuclear News (Oct. 2, 2012).  Retrieved June 17, 2013.

#  D.E. Nunn (SCE) to A. Sawa (Mitsubishi), "Replacement Steam Generators San Onofre Nuclear Generating Station, Units 2 & 3" (Nov. 30, 2004).  Copy retrieved June 17, 2013 from U.S. Senate Committee on Environment & Public Works, attachment to Sen. Boxer's May 28, 2013 press release.

The Mother of Bad Decisions?

This is not about safety culture, but it’s nuclear related and, given our recent emphasis on decision-making, we can’t pass over it without commenting.

The steam generators (SGs) were recently replaced at Crystal River 3.  This was a large and complex undertaking but SGs have been successfully replaced at many other plants.  The Crystal River project was more complicated because it required cutting an opening in the containment but this, too, has been successfully accomplished at other plants.

The other SG replacements were all managed by two prime contractors, Bechtel and the Steam Generator Team (SGT).  However, to save a few bucks, $15 million actually, Crystal River decided to manage the project themselves.  (For perspective, the target cost for the prime contractor, exclusive of incentive fee, was $73 million.)  (Franke, Exh. JF-32, p. 8)*
 
Cutting the opening resulted in delamination of the containment, basically the outer 10 inches of concrete separated from the overall 42-inch thick structure in an area near the opening.  Repairing the plant and replacement power costs are estimated at more than $2.5 billion.**  It’s not clear when the plant will be running again, if ever.

Progress Energy Florida (PEF), the plant owner, says insurance will cover most of the costs.  We’ll see.  But PEF also wants Florida ratepayers to pay.  PEF claims they “managed and executed the SGR [steam generator replacement] project in a reasonable and prudent manner. . . .”  (Franke, p. 3)

The delamination resulted from “unprecedented and unpredictable circumstances beyond PEF's control and in spite of PEF's prudent management. . . .” (Franke, p. 2)

PEF’s “root cause investigation determined that there were seven factors that contributed to the delamination. . . . These factors combined to cause the delamination during the containment opening activities in a complex interaction that was unprecedented and unpredictable.” [emphasis added]  (Franke, p. 27)***

This is an open docket, i.e., the Florida PSC has not yet determined how much, if anything, the ratepayers will have to pay.  Will the PSC believe that a Black Swan settled at the Crystal River plant?  Or is the word “hubris” more likely to come to mind?

* “Testimony & Exhibits of Jon Franke,” Fla. Public Service Commission Docket No. 100437-EI (Oct. 10, 2011).

**  I. Penn, “Cleaning up a DIY repair on Crystal River nuclear plant could cost $2.5 billion,” St. Petersburg Times via tampabay.com website (Oct. 9, 2011).  This article provides a good summary of the SG replacement project.

***  For the detail-oriented, “. . . the technical root cause of the CR3 wall delamination was the combination of: 1) tendon stresses; 2) radial stresses; 3) industry design engineering analysis inadequacies for stress concentration factors; 4) concrete strength properties; 5) concrete aggregate properties; and 6) the de-tensioning sequence and scope. . . . another factor, the process of removing the concrete itself, likely contributed to the extent of the delamination. . . .” From “Testimony & Exhibits of Garry Miller,” Fla. Public Service Commission Docket No. 100437-EI (Oct. 10, 2011), p. 5.