Oconee SRV problems.

I don't like the idea between Oconee and Lasalle they all having two test fails per cycle. It is not big problem, but it is interesting contrasting both plant's Cosby SRVs.

Oconee Nuclear Station

RA-18-0042
June 19, 2018

Subject: Licensee Event Report 287/2018-001, Revision 00 - Two Main Steam Relief Valve Setpoints Found Out of Tolerance

On 4/20/18, prior to shutdown of Unit 3 for refueling, all 16 of the Unit 3 Main Steam Safety Valves, referred to as Main Steam Relief Valves (MSRV) at Oconee, were tested to satisfy Technical Specification (TS} Surveillance Requirement (SR) 3. 7.1.1. The testing found that the as-found lift pressure for two valves was higher than allowed by SR 3. 7.1.1. The remaining fourteen valves met the SR. Guidance from NU REG 1022 Revision 3 states "the existence of similar discrepancies in multiple valves is an indication that the discrepancies may well have arisen over a period of time and that...the condition existed during plant operation". Thus, the event is considered an operation or condition prohibited by TS and is reportable in accordance with 10 CFR 50.73(a}(2)(i)(B).
The causes of the MSRV test failures were determined to be a combination of setpoint drift and binding of spindle and upper spring washer. Although the lift pressures were. above the acceptance criteria, this condition is bounded by current safety analysis limits and assumptions.

EVALUATION:
BACKGROUND

System Design and lnservice Testing (1ST) Program Information There are two steam lines with eight self-actuated safety valves on each line designed to limit over-pressurization of the Main Steam System [EIIS: SB] to 110% of design pressure under all conditions. The Main Steam Relief Valves (MSRV) [EIIS: RV] actuate to relieve excess steam pressure during plant accidents or events such as Turbine/Reactor trips, rod withdrawal accident at power, etc. These valves have staggered set pressures with nominal values that vary from 1050 psig up to 1104 psig. The allowable tolerance range varies from +3 % to -3%; depending on the specified valve. This acceptance criteria is maintained in the Updated Final Safety Analysis Report (UFSAR), Section 10.3.3, "Main Steam System - Safety Evaluation".
Number of Nominal Set Pressure Allowable As-Found Relief Valves per Line ' (psig) Pressure (psig) ' 1 1050 1019-1060 (+1%/-3%) 1 1065 1033 -1096 (+/-3%) 1 1070 1038 -1102 (+/-3%) 1 1075 1043 -1107 (+/-3%) 2 1080 1048 -1112 (+/-3%) 1 1090 1058-1122 (+/-3%) 1 1104 1071-1137 (+/-3%)
Each Oconee Unit has sixteen (16) Crosby, Model HA/HC-65W valves. All sixteen (16) valves are as-found setpoint tested each refueling outage in accordance with the lnservice Testing (1ST) Program. Each valve is disassembled/inspected and refurbished every ten (10) years. These inspections are staggered such that a sample of the population is inspected each refueling outage. Valve 3MS-5 was last disassembled in 2010. Valve 3MS-8 was last disassembled in 2012.
Related Technical SQecifications (TS) and TS Bases Limiting Condition for Operation (LCO) 3.7.1 states: "Eight MSRVs shall be OPERABLE on each main steam line," and is applicable in Modes 1, 2 and 3. The only Condition in TS 3.7.1 is Condition A, which is entered when one or more MSRV is inoperable. Required Action A.1 requires entry into Mode 3 within 12 hours and, A.2 requires entry into Mode 4 within 18 hours, if any MSRV is inoperable. The only Surveillance Requirement (SR) for this specification is SR 3.7.1.1 which states: 'Verify each MSRV lift setpoint in accordance with the lnservice Test Program."
The TS 3.7.1 bases states: "To be OPERABLE, lift setpoints must remain within limits, specified in the UFSAR."
Plant 0Qerating Conditions At the time of this event, Oconee Unit 3 was in Mode 1 at approximately 83% power (Note: Unit 3 was in an end-of-cycle power coastdown in preparation for a refueling outage). There are no safety systems or components that interact with the MSRV's ability to function. No structures, systems, or components were out of service at the time of this event that contributed to this event.
ReQortability Basis Guidance from NUREG 1022 Revision 3 states "the existence of similar discrepancies in multiple [safety] valves is an indication that the discrepancies may well have arisen over a period of time and that. .. the condition existed during plant operation." Thus, the event is considered an operation or condition prohibited by TS and is reportable in accordance with 10 CFR 50.73(a)(2)(i)(B). '

In 2012, a similar event was reported in LER 287/2012-001-00. The cause of these setpoints being out of tolerance was attributed to setpoint drift. The internal inspection of the valves did not reveal signs of actual binding; however, the potential for binding was identified. Planned actions from the 2012 LER included revision of the appropriate procedures to incorporate the latest manufacturer's criteria for the guide bearing inner diameter (ID) into MSRV scheduled Preventative Maintenance (PM). Additionally, the inspection of the spindle, top spring washer ID, and adjusting bolt ID in their contact area was incorporated into station procedures.
EVENT DESCRIPTION
On April 20, 2018, Oconee Unit 3 was preparing to shutdown for a scheduled refueling outage (03R29). As part of the planned activities, maintenance personnel performed MSRV testing prior to shutdown. All sixteen (16) of the MSRVs were tested. Fourteen (14) MS RVs were found within tolerance but two (2) were out of tolerance. t t t
Specifically, valves 3MS-5 and 3MS-8 as-found set pressure was outside the +3% and +1 % allowable range, respectively. Immediately following each testfailure, the control room was notified, the valves were declared inoperable, and the affected valves were adjusted within the as-left acceptance range. Operations was notified that the valves were back within setpoint tolerance.
The following are the specifics for each valve found out of tolerance:
Valve
3MS-5
3MS-8
CAUSAL FACTORS:
3MS-8
Nominal Setpoint (psig) Limit (psig) As-Found (psig)
1080 1112(+3%) 1129 (+4.5%)
1050 1060 (+1%) 1062 (+1.1%)
Time Found Time Restored
0906 0937 1037 1132
The as-found measured setpoint for 3MS-8 was 1.1 % above nameplate. Since no observable abnormalities were found when the valve was disassembled, the failure itself was attributed to setpoint drift; a historical characteristic with relief valves of this design. While enhancements to maintenance and testing can influence setpoint drift, it is recognized as a phenomenon that can't be totally prevented (IN2006-24).
3MS-5 The as-found measured setpoint for 3MS-5 was 4.5% above nameplate. This is outside normal setpoint drift and abnormalities were found when the valve was disassembled. The 3MS-5 MSRV degradation/failure mechanisms were determined to be binding of spindle and upper spring washer coupled with setpoint drift; which accounted for the total +4.5% setpoint variation.
The binding was due to the spindle being bowed out of tolerance. The guide bearing inner diameter was also found to be smaller than the manufacturer's recommended tolerance. Although no obvious signs of binding were found in this area, it could have affected the set pressure. The inner diameter of the guide bearing would have been inspected and increased during the next scheduled disassembly of 3MS-5 based on corrective actions from the 2012 LER.

During a second test (prior to disassembly), the measured setpoint dropped to +3% of nameplate which further suggested internal valve parts were binding during the first lift. Because the second lift was +3% of nameplate and subsequent lifts following adjustments were consistent, there was also an indication of setpoint drift present with this valve.
CORRECTIVE ACTIONS:
Immediate:
Subsequent:
3MS-5 and 3MS-8, which had an as-found result outside of the allowed tolerance, were promptly adjusted within in tolerance and acceptably retested.
3MS-5 and 3MS-8 were disassembled during the 03R29 refueling outage (Work Orders 20247773 and 20247772, respectively). Both valves were machined to the increased inner diameter of the guide bearing. 3MS-8 was reassembled when no abnormalities were found and set to the as-left setpoint criteria at the end of the unit refueling outage. The spindle and spring assembly were replaced on 3MS-5. The valve was reassembled and set to the as-left setpoint criteria during the unit refueling outage.
None of the above corrective actions are NRC Commitment items. There are no other NRC Commitment items contained in this LER.
SAFETY ANALYSIS
The as-found setpoints of 3MS-1 thru 16 measured on 4/20/2018 were reviewed in aggregate and found to maintain peak secondary pressures that are within safety analysis of record. The feedwater flow capacity for decay heat removal and long-term plant cooldown is determined by the lift pressure of the lowest lifting MSRVs. In this case, 3MS-8 and 3MS-16. Although the lowest lifting valve on the "A" Steam Generator (SG) (3MS-8) was found to be 2 psi too high, this condition is more than offset by the lowest lifting valve on the "B" SG (3MS-16) being 22 psi lower than the design value. These as-found setpoints provide sufficient feedwater flow for decay heat removal and long-term plant cooldown when using either the Emergency Feedwater (EFW), Protected Service Water (PSW), or Standby Shutdown Facility Auxiliary Service Water (SSF ASW) systems. Thus, it is concluded that the impact of this condition on overall plant risk is insignificant and had no impact on public health and safety.
ADDITIONAL INFORMATION
A search of the Oconee Corrective Action Program (CAP;) database for the preceding five (5) year period revealed no similar events that occurred at Oconee Nuclear Station (ONS). Additionally, a review of industry Operating Experience (OE) databases was conducted using applicable keyword searches, i.e., "MSRVs setpoint," etc., to ascertain other reported events.
One related event occurred at Oconee prior to the preceding five (5) year period on April 13, 2012. This LER is discussed in the Background section.
Energy Industry Identification System (EIIS) codes are identified in the text as [XX].
This event is considered INPO Consolidated Events System (ICES) Reportable.
There were no releases of radioactive materials, radiation exposures or personnel injuries associated with this event.

Vogtle: US-designed Chinese nuclear reactor forced to shut by pump defect

Electric Power
14 Mar 2019 | 20:31 UTC
Washington 

US-designed Chinese nuclear reactor forced to shut by pump defect 

Author William Freebairn
Editor Keiron Greenhalgh
Commodity Electric Power

Washington — China's Sanmen-2 nuclear reactor, the third US-designed Westinghouse AP1000 unit to begin operating in the world, has been shut temporarily because of a defect in a reactor coolant pump, which is being replaced, a top Chinese nuclear regulator said Thursday.

A replacement reactor coolant pump has been shipped from the US and is expected to arrive at the Sanmen site in the next several weeks, Shirong Zhou of China's National Nuclear Safety Administration said during the US Nuclear Regulatory Commission's annual conference in Washington.

The unit is the third of four US-designed reactors to operate in China. Chinese companies gained ownership of the technology for the design for domestic use as part of a deal to acquire four units from Westinghouse.

The AP1000 design is a next-generation reactor model that is also being built at Georgia Power's Vogtle plant in the US.

Each AP1000 includes four of the sealed reactor coolant pumps, which have had design and quality problems before.

The AP1000 design at one time had been considered for widespread deployment in China, but delays in construction related to earlier issues with the US-built reactor coolant pumps have reportedly led Chinese decision-makers to favor a domestic reactor design for deployment in larger numbers.

The problem appears to be related to the motor for the giant pump, Zhou said. An initial investigation shows there was leakage around supports for the pump, but a full investigation will have to wait until the defective pump is disassembled and examined after removal, he said.

The reactor coolant pumps, which move coolant around the primary cooling circuit of the reactor, are the largest so-called "canned pumps" to ever be used in a nuclear reactor. The hermetically sealed pumps are designed to operate without leakage and contain a sealed motor system.

Sounds like Curtiss-wright with their safety relief problems. Doesn't look good with all the prestartup problems and now they got to replace the pump.  

The pumps were manufactured by US-based Curtiss-Wright. During construction of the Sanmen and Haiyang units in China, several of the pumps were returned from China to the US for repairs after a defect was discovered that resulted in localized heating of the pumps.

Westinghouse and Curtiss-Wright are engaged in a dispute over responsibility for delivery delays for the pumps in China and the US, Curtiss-Wright has said in financial filings.

With the exception of the pump problem, the overall operating experience of the four AP1000 reactors in China has been good, Zhou said...

LaSalle Crosby Safety Relief Valve LERs

Update May 13 works in progress

I was in a phone meeting with at least two NRC region III officials yesterday, the inspectors boss and a regional equipment specialist.

My pitch is the cosby SRVs have worked flawlessly for at least a decade. I actually might have added pressure in and around 2003, that the current SRVs was defective in 2003 and that is why they got the Crosby in them today. They had a host of leaking and valves with operational problems. See the docket on my comments in and around 2003. I believe this is when they went to the cosby valves.

Pressure setpoint drift problems: Technical Specification violations

Unit 1

LER-2018-003-01 (2 vlvs failed test)

Unit 2

LER-2017-002-02 (2 vlvs failed test

LER-2017-004-02 (2 vlvs failed test)


So they have been working perfectly till 2015. This isn't a one plant facility...its a two plant facility. Then unit 1 had two SRV's setpoint drift problem out of 13 SRVs. Plant 2 began having problem in about 2017 with two valves failing teck specs and then again in 2018 with two failing again on  setpoint drift. My take is all of a sudden in 2015 setpoint drift failures showed up ending with 6 failed test, albeit it failed by just a few psi. All found failing for unknown reasons. The NRC's take is the laSalle discovered defected and corrected the problem like in 2015. I came back with, "well, it seems the corrective actions didn't work in 2015, as we had a another failure 2017. And the corrective actions in 2017 didn't work also as we had another failures of two in 2018. So out of three LERs, with got 6 valves that failed for unknown reason. The NRC could throw at LaSalle a expensive route cause analysis on the failed SRVs, but they don't have a good enough reason for as yet. I thought that would be a good idea as it would send a message to LaSalle and the rest of the industry. I told them I thought we had reason to suspect we got vendor testing paperwork falsification issues going on. Out of three testing cycles, we got three LERs describing two failed test each. Finding exactly two failed test over three cycles seems like wining the $800 million dollar lottery to me. I reminded the NRC I think the testing vendors can make the testing result sing to  any tune of the licensees.

NRC officials poorly trained on SRV operations and maintenance issues throughout the industry precipitated by the NRC's poor documentation of historical operation and maintenance. This poor historically documentation, like some kind of repetitive 2 year industry notification, leads to the effect of inadequate training on reactor safety equipment to inspectors and within the senior leadership of the NRC. I believe this effects more than safety relief valve issues.             


Update May 12

I got a call yesterday afternoon from Allegations Sara that new information has just come in and the agency wants me to hear it. I got a tele conference with a few NRC officials and the licensee this morning at 9:30 am. That is why I am looking over this article this morning. Bells are ringing when the NRC says they got new information they want me hear and maybe the license will be in the meeting. Is this coming from the new US House election?      
***reposted from 2/20

***Reposted from 2/19 

NRC search for safety relief valve LERS for the last ten years

Unit 1 Cosby LERs

Licensee Event Report 2018-003-01, Two Main Steam Safety Relief Valves Failed lnservice Lift Inspection Pressure Test 

These Below LER are not into the system. 

During the February 2015 Unit 2 refueling outage L2R15, two main steam safety relief valves (SRV) did not pass TS Surveillance Requirement 3.4.4.1 and lnservice Testing Program lift pressure requirements. Both SRVs lifted below their expected lift pressures and were replaced during the outage. A failure analysis was conducted by a vendor testing laboratory, but the cause for the valves lifting below their set-point was indeterminate. 

LER Unit 2 374-2017-004-01 : During the February 2017 Unit 2 refueling outage, two main steam safety relief valves (SRV) did not pass TS Surveillance Requirement 3.4.4.1 and lnservice Testing Program lift pressure requirements. Both SRVs lifted below their expected lift pressures and were replaced during the outage. A failure analysis was conducted by a vendor testing laboratory, but the cause for the valves lifting below their set-point was indeterminate.

LER Unit 2
SRV 1 B21-F013U 
1 B21-F013U 

Unit 2 LERs

Licensee Event Report 2017-004-02, Two Main Steam Safety Relief Valves Failed lnservice Lift Inspection Pressure Test 

SRVs 2B21 ·F013C
2B21·F013L

Licensee Event Report 2015-002-00, Two Main Steam Safety Relief Valves Failed Inservice Inspection Pressure Test
SRV 2B21-F013S 
 2821-F013M

***I talked to Sara of Allegations and then to two inspectors at the plant. These two inspectors couldn't believe a utility would routinely enters LCOs over SRV lift setpoint drift inaccuracies, a required shutdown over disc and seat corrosion bonding if known, are required to fix the problem or submit a license amendment request to change TS. I told these guys plants like Hope Creek and Pilgrim routinely with SRVs, either refurnish the valves on site or replace the refurbished valves from a vender. These is utterly no necessity of fixing the latent problems like corrosion bonding. The NRC decided these setpoint drift repeated problems violated tech specs and are defined as safe on a whim. I found these inspectors light on training surrounding SRVs, Tech Specs and problems with SRVs.    

Mike, the utilities only has two choices here with this problem. These guys are so naïve and poorly trained on TS and SRV problems in the industry. I said, these plants regularly go into a LCOs over the SRVs.

***Everything is deregulation. Granted they failed Tech Specs by a small amount. These are Crosby valves which have a good reputation as far as I can see. But if they were up at power and discovered a LCO, they would have had to shutdown. This penalty is supposed to get them to fix or replace the valves. They seem to not have the same problem with Target Rock valves seat and disc sticking together...corrosion bonding.

You notice, they have no idea why the valves failed?

The valves pressure set point test probably started out at  plus or minus 1% many years ago. After troubles, they relaxed the testing requirements to plus or minus 3% that needed a LAR. Now in the future, its going to be plus or minus 5%. They are going to plus or minus 5% on the target rock relief valves. I think this is dangerous behavior, just repetitive relaxing requirements because of component failures

LER 2018-003-01

During the February 2018 Unit 1 refueling outage, two main steam safety relief valves (SRV) did not pass Technical Specification (TS) Surveillance Requirement 3.4.4.1 and lnservice Testing (IST) Program lift pressure requirements. Both SRVs lifted below their expected lift pressures. On February 27, 2018, SRV 1B21-F013R was required to lift within plus or minus three percent of 1205 psi (i.e., 1205 psi plus or minus 36.1 psi), but lifted at 1167 psi. On February 27, 2018, SRV 1 B21-F013U was required to lift within plus or minus three percent of 1150 psi (i.e., 1150 psi plus or minus 34.5 psi), but lifted at 1109 psi.  

Multiple test failures are reportable under 1 O CFR 50. 73(a)(2)(i)(B) as an operation or condition prohibited by the plant's TS. Both SRVs lifted prior to their expected lift pressures, which is conservative regarding maintaining reactor pressure vessel over-pressure limits. Both SRVs were replaced during the outage. A failure analysis was conducted; however, it did not identify a cause for the valves lifting below their expected lift set-points.

LaSalle County Station (LSCS) Unit 1 is a General Electric Boiling Water Reactor with 3546 Megawatts Thermal Rated Core Power.  

The main steam safety relief valves (SRVs) are designed to prevent over-pressurization of the reactor pressure vessel (RPV) during transients and abnormal conditions, which protects against a failure of the reactor coolant pressure boundary (RCPB). There are thirteen SRVs installed on the four main steam lines, which discharge near the bottom of the suppression pool to condense the steam through SRV tailpipes that exhaust beneath the suppression pool surface.
CONDITION PRIOR TO EVENT
Unit(s): 1 Date: Reactor Mode(s): 5 Mode(s) Name:
DESCRIPTION OF EVENT
February 27, 2018 Refueling
Time: Power Level:
1520 CST O percent
01
During the February 2018 Unit 1 refueling outage, two main steam safety relief valves (SRV) did not pass Technical Specification (TS) Surveillance Requirement (SR) 3.4.4.1 and lnservice Testing (IST) Program lift pressure requirements. Both SRVs lifted below their expected lift pressures. On February 27, 2018, SRV 1 B21-F013R was required to lift within plus or minus three percent of 1205 psi (i.e., 1205 psi plus or minus 36.1 psi), but lifted at 1167 psi. On February 27, 2018, SRV 1 B21-F013U was required to lift within plus or minus three percent of 1150 psi (i.e., 1150 psi plus or minus 34.5 psi}, but lifted at 1109 psi.
CAUSE OF EVENT
A failure analysis was conducted; however, it did not identify a cause for the valves lifting below their expected lift set-points.
Station operating experience has shown a tendency for a portion of LSCS SRVs to experience minor setpoint drift sufficient to exceed the acceptance criteria of minus three percent over time. A license amendment request (LAA) was submitted to the NRC on February 27, 2018 to revise TS SR 3.4.4.1 to lower the setpoint tolerances for Unit 1 and Unit 2 SRVs. This proposed change would revise the SRV as-found lower tolerances from minus three percent to minus five percent to account for minor SRV setpoint drift in the conservative direction. This proposed change will reduce the unnecessarily restrictive surveillance requirement and will not impact the reliability of the SRVs or adversely impact their ability to perform their safety function. The change will reduce the number of TS SRV surveillance test failures for early lift pressure and preclude the submittal of previously reportable licensee event reports to the NRC due to setpoint drift in the low (conservative) direction... 

NRC's 2018 Plant Assessment: Every One Got 'A' s and 'B' s

NRC Issues Annual Assessments for Nation’s Nuclear Plants

The Nuclear Regulatory Commission has issued annual letters to the nation’s 98 commercial nuclear power plants operating in 2018 regarding their performance throughout the year. All were in the two highest performance categories.

Ninety-three of 98 fully met all safety and security performance objectives and were inspected by the NRC using the normal “baseline” inspection program.

Four reactors were assessed as needing to resolve one or two items of low safety significance. For this performance level, regulatory oversight includes additional inspection and follow-up of corrective actions. Plants in this level are: Grand Gulf (Mississippi); Peach Bottom 2 & 3 (Pennsylvania); and Watts Bar 2 (Tennessee). Watts Bar 2 resolved its issues since the reporting period ended and has transitioned to the highest performing level.

The Failed Summer Nuclear Plant: They Are All Liars

This is becoming truth that somebody turned off the NRC inspectors.

Lawyer: Ex-SCANA officials ‘whitewashed,’ lied about defects at failed nuclear plant

John Monk, The State Published 10:10 a.m. ET March 5, 2019

CONNECTTWEETLINKEDINCOMMENTEMAILMORE

OLUMBIA, SC 

SCANA executives deliberately lied to investors about the future of a doomed nuclear construction project, a lawyer representing former SCANA shareholders argued in court Monday.

“The bottom line is they (SCANA executives) lied to everyone, and they did it intentionally,” attorney John Browne told U.S. Judge Margaret Seymour.

The cost was tremendous, said Brown, whose lawsuit argues shareholders lost some $2.7 billion in stock value when the company’s stock price plummeted.

Seymour has a crucial decision to make about Browne’s lawsuit that alleges SCANA executives committed civil fraud that deflated investors’ stock valuations. She will decide whether to allow Browne’s lawsuit to go forward or dismiss it. She gave no hint Monday on how she might rule, or when.

Watching the proceedings Monday at the federal courthouse in Columbia were several attorneys from the U.S. Attorney’s office, which is working with the FBI to investigate criminal fraud allegations against SCANA and some of its former executives.

Federal law officials are keeping a low profile, but the investigation into the now-abandoned nuclear project in Fairfield County is an open secret in the state’s legal community.

The U.S. Attorney’s office would not comment on the investigation Monday.

During the hearing, Browne referred repeatedly to a document known as the Bechtel Report, which SCANA commissioned in 2015 to evaluate progress on the V.C. Summer nuclear plant under construction.

Scott Elliott tells the VC Summer committee that, after studying the Bechtel report, that SCE&G should have disclosed it's findings.

The Bechtel report, a draft of which was presented to SCANA the fall of 2015, detailed substantial cost overruns, construction delays and shoddy work at the nuclear plant site. But the report was never publicly released or discussed.

The company, which was publicly traded on the New York Stock Exchange, hid its findings from investors, the press and the public, Browne said.

“They treated it (the Bechtel report) as something to hide! They treated it as something to whitewash! They treated it as something to bury!” Browne said. He told the judge SCANA wanted to portray the nuclear plant’s ongoing construction as “hunky-dory” and “rosy” so as not to deflate the stock price.

During a 10-month period, from about late December 2016 to late-October 2017, as SCANA’s woes at the nuclear facility became known, SCANA’s stock price plummeted from to $43 a share from $72.

SCANA and its junior partner on the project, state-owned Santee Cooper, announced they were abandoning construction on the project on July 31, 2017.

The chaos unleashed by the nuclear failure led to SCANA, once a profitable showpiece of the state’s business community, being sold to Virginia-based energy giant Dominion Energy earlier this year at a bargain price.

At Monday’s hearing, lawyers representing SCANA and the company’s former executives belittled the claims by Browne that the company’s public statements about progress in 2015, 2016 and 2017 on the nuclear power plant were deliberately meant to mislead the public.

On the contrary, attorney Matthew Martens told the judge, SCANA was consistently open with investors and made sure that people knew the nuclear project was not a sure thing.

“Were risks disclosed? They were disclosed extensively by Mr. Bryne,” Martens said, referring to his client, Stephen Byrne, SCANA’s former chief operating officer. “No one was misled.”

Statements by Bryne and other SCANA officials were informed opinions by officials giving their best, honest assessments of the nuclear project, Martens said.

“There’s no argument that if you make a statement about something that turns out not to be true, that it is going to turn into securities fraud,” Martens said.

SCANA lawyers referred repeatedly to a legal term called “scienter” — meaning that former SCANA shareholders will have to prove that the SCANA executives intended to deceive the public. That’s difficult to prove in most cases.

Moreover, SCANA lawyers said, the shareholder plaintiffs can’t show that the executives enriched themselves by selling big batches of stock at inflated prices or accepting unusual bonuses.

State Sen. Marlon Kimpson, D-Charleston, a lawyer representing the plaintiffs told the judge that news about the project continues to unravel that supports claims about SCANA’s intention to deceive investors and SCANA retirees — many of whom owned SCANA stock.

“We are ready to hit the ground running,” said Kimpson, whose side has compiled a 200-plus page complaint packed with specific instances of alleged deceit by SCANA.

Ouch: Mike Mulligan Get into Car Wreck

Went to my old home town yesterday to go out hiking. Walked and hiked all day. Around 9 pm got to within 1 mile of my house in Hinsdate. Hit a tree right in the middle of my hood off the road. A car was coming down a hill with his headlight on. I diverted my eyes away from the lights, I was off the road in about a second, then hit a pole going at around 30 MPH. I was completely by myself. Airbags came right on. Still kind of hazy with the sequence, think I got a slight concussion. Refuse the go to the hospital. Think they had three ambulance or more on the scene, plus maybe four or five police cruiser and maybe four fire trucks. Seat belt side feels like a broke a rib, really hurts through the night. Better right now. I have embarrassd myself terribly with not paying attention to the road. No tickets. There were sniffing me and my car pretty seriously...But I wasn't on anything.