ML19273A082
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| Issue date: | 09/25/2019 |
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1 UNITED STATES NUCLEAR REGULATORY COMMISSION FEDERAL ENERGY REGULATORY COMMISSION
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JOINT MEETING OF THE FEDERAL ENERGY REGULATORY COMMISSION (FERC) AND THE NUCLEAR REGULATORY COMMISSION (NRC)
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WEDNESDAY, SEPTEMBER 25, 2019
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ROCKVILLE, MARYLAND
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The Commissions met in the Commissioners= Hearing Room at the Nuclear Regulatory Commission, One White Flint North, 11555 Rockville Pike, at 9:00 a.m., Neil Chatterjee, FERC Chairman, and Kristine L. Svinicki, NRC Chairman, presiding.
2 FEDERAL ENERGY REGULATORY COMMISSION MEMBERS:
NEIL CHATTERJEE, Chairman RICHARD GLICK, Commissioner BERNARD L. MCNAMEE, Commissioner NUCLEAR REGULATORY COMMISSION MEMBERS:
KRISTINE L. SVINICKI, Chairman JEFF BARAN, Commissioner ANNIE CAPUTO, Commissioner DAVID A. WRIGHT, Commissioner ALSO PRESENT:
ANNETTE VIETTI-COOK, Secretary of the Commission FERC STAFF:
PATRICIA EKE, Energy Industry Analyst, Office of Electric Reliability DAVID HUFF, Electrical Engineer, Office of Electric Reliability ANUJ KAPADIA, Electrical Engineer, Office of Electric Reliability
3 NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION (NERC)
STAFF:
MARK LAUBY, Senior Vice President and Chief Reliability Officer NRC STAFF:
ERIC BENNER, Acting Deputy Director for Reactor Safety Programs and Mission Support, Office of Nuclear Reactor Regulation (NRR)
ANNA BRADFORD, Deputy Director, Division of Licensing, Siting, and Environmental Analysis, Office of New Reactors (NRO)
MEENA KHANNA, Acting Deputy Division Director, Division of Materials and License Renewal, NRR
4 1 PROCEEDINGS 2 9:03 a.m.
3 NRC CHAIRMAN SVINICKI: Good morning, everyone, 4 and welcome to this morning's meeting. This is one of our somewhat 5 routine -- and we try to have these on a fairly regular schedule -- joint 6 convenings of the U.S. Nuclear Regulatory Commission as well as the 7 Federal Energy Regulatory Commission. So, we are joined by our 8 colleagues from FERC today. We welcome you to the NRC.
9 We do alternate locations. So, our quarters are a little 10 bit tighter here at the table. Apologize for that. But it's wonderful to 11 have you here today.
12 We are meeting in public session on a number of topics, 13 but, in general, I would just casually characterize these meetings as we 14 have responsibilities and authorities that kind of touch each other. They 15 don't I think in the strictest sense overlap, but it is important I think both 16 for our expert staffs to work closely, which they do throughout the course 17 of the year, but I think it's also extremely useful to have the members of 18 each Commission convene as well.
19 And I will recognize the Chairman of FERC for any 20 opening comments he would like to make, Mr. Chatterjee, and then, other 21 members, if they would like to.
22 So, Neil, please.
23 FERC CHAIRMAN CHATTERJEE: Thank you, and
5 1 good morning, everyone. I'd like to thank Chairman Svinicki, the 2 Commissioners from the Nuclear Regulatory Commission, and their staff, 3 for welcoming FERC participants to the NRC Headquarters.
4 Both of our Commissions play a critical role in ensuring 5 that our nation's critical infrastructure remains safe, affordable, and 6 secure for all Americans. Last year was the first time I attended this joint 7 meeting, and I was impressed with the information shared between both 8 Commissions.
9 Like my predecessors, I'm committed to carrying out the 10 Memorandum of Agreement between our organizations which states that 11 we mutually coordinate, prioritize, integrate, and manage tasks related to 12 the nation's electric power grid reliability and nuclear power plant safety 13 and security, including but not limited to coordination of activities related 14 to cybersecurity, physical protection, and emergency response. I'd like to 15 thank staff from both Commissions and from NERC for the presentations 16 that they have prepared. These presentations will highlight the critical 17 nature of our work in the areas of electrical reliability and infrastructure 18 security, both cyber and physical.
19 Specifically, among other topics, we will hear from 20 FERC staff an overview of their joint report with NERC and its regional 21 entities on the South Central U.S. Cold Weather Bulk Electric System 22 Event that occurred on January 17th, 2018, emphasizing the importance 23 of planning for extreme cold and communicating during times of system
6 1 stress.
2 We will also hear from FERC staff on energy storage 3 technologies and the implementation status of FERC Order 841 which 4 dealt with electric storage.
5 Finally, FERC staff will provide an update on several 6 FERC cybersecurity rulemakings and lessons learned from our 7 cybersecurity audits.
8 So, again, I want to thank the Chairman, the NRC 9 Commissioners, and the NRC staff for their hospitality, and I look forward 10 to hearing all of the presentations prepared by both FERC, NRC, and 11 FERC staff, and NERC.
12 Thank you.
13 NRC CHAIRMAN SVINICKI: Thank you very much, 14 Chairman Chatterjee.
15 Would either member of the Federal Energy Regulatory 16 Commission like to make an opening statement? Please proceed.
17 FERC COMMISSIONER GLICK: Thank you. Thank 18 you, Madam Chair. I want to thank the NRC for hosting us this year. I 19 actually got a lot out of last year's meeting, and I think today we'll be 20 doing the same.
21 I also want to thank the staff for their work, their hard 22 work in planning all this, both Agencies. It's been very helpful and I 23 appreciate the information that you provided.
7 1 Nuclear power continues to play an important role in the 2 nation's electricity mix, and it's important to note, especially this week 3 during which the United Nations held its Climate Change Summit in New 4 York, that nuclear energy, because it's a greenhouse gas, emissions-free 5 resource, is going to play a significant role in helping some of the states 6 meet their clean energy goals.
7 As our electric grid evolves, it also faces new and 8 evolving threats. Cybersecurity is a critical priority for both FERC and 9 the NRC, and I look forward to the presentation on the NRC's 10 Cybersecurity Program that we're going to be receiving in a little bit.
11 I appreciate the opportunity to be here today, and I want 12 to continue the good work and relationship between our Agencies. So, 13 thank you very much.
14 NRC CHAIRMAN SVINICKI: Thank you very much, 15 Commissioner Glick.
16 Commissioner McNamee, would you like to make a 17 statement?
18 FERC COMMISSIONER MCNAMEE: Great. Thank 19 you, and thank you for hosting us today. And thank you for everybody 20 who's here.
21 And I also want to thank the staffs at the NRC, FERC, 22 and NERC for being here and for the work that they've done in helping 23 prepare for this.
8 1 Reiterating what my colleagues have said, the 2 importance of nuclear energy to our electric system can't be overstated.
3 It currently provides about 20 percent of our electric generation, and it 4 does provide an important source of electricity for our nation.
5 I think it's appropriate that we meet on an annual basis 6 to talk about these issues together and the importance that nuclear power 7 plays in our country. It is also important that we talk about grid reliability, 8 cybersecurity issues, and discuss issues about new innovation. I know 9 that the NRC, especially from my time when I was at DOE, knowing how 10 you look into the issues of licensing and how new technology develops is 11 vitally important to helping move this country forward in nuclear energy.
12 So, I thank you for the work that you do on that.
13 I look forward to today's event, to the conference, and 14 look forward to learning a lot. Thank you.
15 NRC CHAIRMAN SVINICKI: Thank you very much, 16 Commissioner.
17 Would any member of the NRC Commission like to 18 make a statement? Commissioner Baran?
19 NRC COMMISSIONER BARAN: Just briefly join you in 20 welcoming our FERC colleagues. It's great to have you here.
21 I think it is maybe the fourth time I've done the joint 22 FERC-NRC meetings, and I've found them always to be very valuable.
23 There are so many common areas of interest where maybe we don't
9 1 overlap, but, as the Chairman said, our jurisdictions touch. And so, I'm 2 looking forward to the presentations.
3 Thanks for being here.
4 NRC CHAIRMAN SVINICKI: Thank you very much.
5 Any other member? Commissioner Caputo?
6 NRC COMMISSIONER CAPUTO: I will add my 7 welcome to our FERC colleagues. Thank you for coming, and to all of 8 the FERC, NERC, and NRC staff for preparations for today.
9 I really enjoyed my first meeting, joint meeting, last year 10 as a new Commissioner. So, I'm eager for the discussion today. Thank 11 you.
12 NRC CHAIRMAN SVINICKI: Thank you.
13 Commissioner Wright?
14 NRC COMMISSIONER WRIGHT: Thank you so much.
15 Again, I want to join everyone in welcoming our FERC 16 colleagues here. It's been a pleasure to get to know you in the very short 17 time that we've been here. And like Commissioner Caputo, if it wasn't 18 our first meeting, it was our second, you know, and it was like drinking 19 from a fire hose. So, I feel your pain on that.
20 Thank you so much for being here, and I look forward to 21 the dialog.
22 NRC CHAIRMAN SVINICKI: Thank you very much.
23 With that, now we will begin with the presentations.
10 1 And I think as we've done in years past, we will begin with Mr. Mark 2 Lauby, who is the Senior Vice President and Chief Reliability Officer of 3 NERC, for his presentation.
4 Please kick us off. Thank you.
5 MR. LAUBY: Thank you, and I really appreciated the 6 invitation. Delighted to be here, and I enjoy coming to the NRC, 7 especially because of the intimate way in which we interact.
8 So, just out of the box, I wanted to explain --
9 MS. VIETTI-COOK: I'm just going to get that a little 10 closer to you.
11 MR. LAUBY: All right. Thank you very much. Is that 12 better?
13 NRC CHAIRMAN SVINICKI: It is, and I would just note 14 our microphones have a really small sweet spot. So, just sometimes 15 we'll adjust. Please don't be offended. Thank you.
16 MR. LAUBY: Thank you.
17 Just to explain briefly, NERC has multiple functions 18 when it comes to looking forward and looking at the risks on the bulk 19 power system as well as, then, measuring the ongoing performance. We 20 have our long-term reliability assessment, of course, that looks 10 years 21 out. We have a Reliability Issues Steering Committee that's going to be 22 coming out with a report in November, looking forward at what are the 23 emerging risks on the bulk power system. That helps us kind of tee off
11 1 as to what to monitor on an ongoing basis.
2 And then, we gather lots of data and information around 3 the performance of the system. That is what we put together into our 4 State of Reliability Report that's on an annual basis. Usually, it's out in 5 June, so June looking at 2018, and maybe doing a bit of a comparative to 6 earlier years. That's what you're going to be seeing today.
7 We've kind of re-scoped the report a little bit to make it 8 a little bit easier to read, we hope, kind of set up for computers, rather 9 than printing paper out like old people like me do all the time. I've got to 10 have my paper copies. But a lot of folks do things on their computers.
11 So, we set it up that way.
12 So, getting into the key findings and recommendations 13 in that report, we found that 2018 had no non-weather Category 3, 4, and 14 5 events. These are categorizations which kind of tell us about the 15 relative severity. And we did have a hurricane, of course, Michael and 16 Florence, which were at Category 3, and those were weather-related.
17 Extreme weather events continue to be a leading 18 contributor to the largest generation and distribution outages we saw in 19 2018. But we did also see a better-than-expected performance in the 20 Texas fleet because they've had tight reserve margins there. What that 21 means is that we traditionally get a reserve margin based on some 22 statistical analysis that takes us to about one event in 10 years. And that 23 usually generates kind of a reserve margin. Then, we call that kind of a
12 1 target, and that's total generation divided by total load, and then, we get a 2 percentage.
3 So, they're getting tighter there because they've been 4 having an acceleration in some of the units that are retiring. And even 5 this year, I think they are at about 7 percent reserve margin, which makes 6 engineers a little bit worried because you don't have as much flexibility if 7 certain things happen on the system. But they were able to navigate that 8 in 2018, and it appears that they also did that in 2019 as well. They will 9 be doing an after-action review on that.
10 We continue to see a downward trend in relay 11 misoperations. That's always been one of those things that 1 in about 12 12 operations ends up being a misoperation. We're trying to drive that 13 number down, working with the industry, working with the manufacturers, 14 like Schweitzer, relaying.
15 We are seeing improving our stable frequency 16 response. That's important because, as we start replacing generating 17 plants with asynchronous, you know, with inverter-based, you lose some 18 of that heft. So, how is our frequency response against events? And 19 emerging reliability challenges we found in the inverter-based resources.
20 And I'll get into that a little bit more, but, basically, the way they were 21 operating.
22 Next one, please.
23 This is kind of "by the numbers," you might say. I
13 1 would focus some of your attention on the 99.92 percent of the time that 2 there was no operator control load shedding. That essentially was one 3 event, and I believe it was in Nova Scotia or New Brunswick. And it was 4 for seven hours. So, if you take 7 over 8760, then you get to that 5 number.
6 We can also see how many DOE OE-417 reports were 7 received, 233; how many messages were in the Reliability Coordinator 8 issues, our information system, 1855. We had one Level 2 alert, and it 9 was around those inverters. A Level 2 means we go out and we ask for 10 information to be sent back to NERC. We, then, wrap up a report to 11 FERC on the results, and then, use that information to see the extended 12 condition and next steps. So, that kind of gives you an idea kind of by 13 the numbers and the year.
14 Next slide, please.
15 So, from an event analysis perspective, this kind of 16 gives you an idea of the number of events we have. We gather 17 information about individual line outages, generator outages, but also we 18 look at events. And sometimes we do a deep dive to learn, get the 19 lessons learned on each one of those events. And you'll see the number 20 of Category 1, 2, and 3 to each other. You also see a relative 21 comparison over there to the right, as well as some of the major causes, 22 being, for example, design and engineering. Management and 23 organization is what we see when we do the deep-dive events analysis.
14 1 The next slide, then, of course, this is kind of our event 2 analysis trends. This is when we select an event that occurs, be it a 1, 2, 3 or 3, and then, we do a dive, working with the industry partners and 4 regional entities. And how many reports we received, 856; how many 5 did we actually do a deep dive on, 378. And you can see the major 6 causes. Again, as I mentioned before, we're seeing management and 7 organization. This is something we need to work with industry on a little 8 bit more. Design and engineering being part of the issues around 9 events, and then, finally, equipment failures, and that kind of thing.
10 You'll see an overall of 116 megawatts. This is an 11 average loss of load, but not due to weather; everything under equipment 12 failures, et cetera. Then, you'll see an interesting trend here where the 13 amount of average load being lost is going down, even though the 14 number of events went up. So, that may be more around design of the 15 system itself.
16 Next slide, please.
17 Let's look a little bit more now at some of the reliability 18 indicators.
19 Next slide.
20 Here, this includes weather, this particular set of trends 21 on transmission-related events that resulted in load being shed. That's 22 why you're seeing that going up closer to 200 megawatts versus the other 23 one being about 116. But the number has gone down, as well as the
15 1 amount of megawatts on average has gone down, too. So, things seem 2 to be getting better. And this does include weather.
3 Next slide.
4 Protection rates, annual protection system, this 5 operation rates. You'll see just a bit of a popup in 2018, but, generally, 6 overall, the trend you can see is still heading south, which is good 7 considering we started a little bit over 10, and now we're at about 8, we 8 have dropped down to about 6 and a half, makes this 7 and a half.
9 And you can also see the regional variance here. Of 10 course, we work with each one of these regions, especially when they're 11 over, identify who the folks are and work with those folks to help them get 12 their arms around what the issues are.
13 As you know, there's a lot of relays. And so, it takes 14 time to start driving this rate down. Some of it is best practices. Some 15 of it is newer relays, what have you.
16 Next slide, please.
17 Now Severity Risk Index, this is something we kind of 18 show every year.
19 Next slide.
20 And it weighs the number of lines that go out, the 21 amount of megawatts generations. And what you'll see overall is 2018 22 really was a pretty good year. We had a couple of storms, winter storms 23 and Hurricane Florence, as I mentioned before, and Michael you can see
16 1 kind of on the far left side.
2 If you go to the next slide, you'll see a cumulative as 3 opposed to a day-to-day. And again, 2018 looked pretty good compared 4 to the earlier years.
5 Next slide.
6 Okay. I mentioned before our alert that went out.
7 What we found was there was a simple line-to-ground fault on a 500-kV 8 line, and they lost over a thousand megawatts of solar. It was spread 9 out, of course, across the system. And working with industry and 10 manufacturers, we identified two things. One was how they were 11 calculating frequency, as an instantaneous versus a time-varying. And 12 the other was that they were kind of just momentarily ceasing to operate 13 during serious line-to-ground faults or lower voltages.
14 So, that's not always a good thing, either one of those, 15 and that's one reason why we're losing our inverter-based resources 16 there, and mostly within the West, mostly in California and Nevada. But, 17 of course, it's an issue that could be widespread across North America.
18 So, we wanted to get our arms around it.
19 We sent an alert asking folks, you know, how many they 20 have; can they be fixed, and then, how would they be fixed. And so, in 21 response to 13.5 gigawatts, you can see over here the flow diagram, that 22 some did not use momentary cessation. So, they're staying in, staying 23 put, and that's what you want them to do because that helps support the
17 1 system when you have an event. Then, of course, those that were using 2 momentary cessation, the question is, can you fix it, because some of 3 them may be older inverters, older control systems. And we were able to 4 kind of get that down to about 1.8 gigawatts couldn't be fully mitigated.
5 At least they'll know that ahead of time. So, in their operating system, 6 they'll take that into account. And, of course, then, 2.6 could be 7 mitigated through settings changes and some are just a fully mitigated 8 array. The top curve kind of talks a little bit about frequency calculations 9 and being able to fix that as well. And so, that gives you an idea.
10 We're still following up on this and making sure we've 11 got full response, and we now kind of understand kind of the -- we've 12 been writing a host of guidelines and design issues around this, so that 13 we can get our arms around it. We're also addressing this through a 14 modification of a standard.
15 Overall, the recommendations: industry needs to 16 continue to improve their ability to understand, model, and plan for the 17 system. These new technologies are coming really fast, and we have to 18 be able to model and simulate and understand, perhaps even real-time 19 modeling. So, there may be new technologies there.
20 Certainly we need to watch for frequency response 21 under low-inertia conditions and understand how inverter-based 22 resources can actually contribute to reliability. They can if you design 23 them right and call for VARs and call for frequency. They can support
18 1 the system.
2 Also, the second item, developing comparative metrics 3 to understand the different dimensions of resilience. And that's actually 4 a goal NERC is building into its goal for next year.
5 And understand and share information on cyber or 6 physical security threats, and mitigate those risks through a variety of 7 approaches. I still believe that you can plan a more robust system, so it's 8 more resistant to cyber-attack. And we're going to be digging into that 9 with industry next year.
10 I was also asked to give just a quick overview of where 11 we are with the EMP Task Force. We've been watching the research 12 that's being done at EPRI over the last few years that included, first, the 13 transformers, because there's three wave fronts that occur as a result of a 14 nuclear blast over the Mother Earth, and E3, which impacts the 15 transformers. And they found there that there was no damage to 16 transformers. Generally, again, a voltage collapse issue, which is what 17 we found with GMD.
18 But there is a concern around the E1, the first pulse.
19 And they did a lot of research there showing what were the 20 susceptibilities of certain relays. And so, looking at the results of the 21 report, we've spun up a group to say, okay, what are the next steps for 22 NERC? Given that we're still kind of in the middle of the research, how 23 do we get in front of this issue? How do we start thinking about spec'ing
19 1 relays, potentially higher sustain rates or design issues. So, we spun 2 this group up in May of 2019. They're gearing to have our final report to 3 the Board in November. It's been posted for public comment.
4 You can see kind of the phased-report approach on the 5 next slide. This is the Phase 1, Strategic Recommendations. Then, of 6 course, get some technical committee work ongoing; start doing some of 7 the design and modeling. And then, of course, get a standard drafting 8 team up and running, if it makes sense.
9 And then, I've got kind of different types of topics that 10 you'll see in that report: policy, government and regulators, what can 11 they be doing? The research that needs to be done. We've got to look 12 at generating plants. We've got to understand the impacts on distribution 13 systems. We've got to understand how we can use different designs to 14 mitigate the impacts and, of course, mitigation guidelines. How do you 15 assess your vulnerability, you know, based on different types of blasts 16 and directions?
17 What they found, basically, was that the relay itself, 18 when it gets that E1 pulse, it does not impact it, but it is the 19 communication cables that come into the relay that induces a current and 20 voltage which comes into the relay and potentially damages or, at least 21 worst case, makes it reset. So, you're out there running, thinking you've 22 got a relay, but you don't.
23 And then, how do you respond and recover? How do
20 1 you get back up? What you're on your butt, how do you get back up 2 again?
3 So, that's kind of a high-level review. The report itself 4 is out for comment. I think they will be wrapping up those comments 5 here soon and bringing it to the Board in November.
6 NRC CHAIRMAN SVINICKI: Thank you very much, 7 Mr. Lauby.
8 Under the informal practice we've developed for these 9 meetings for topics that fall outside the domain of a Commission, we start 10 with those members to ask questions. And that makes some intuitive 11 sense because we're less familiar with the topic.
12 So, for this NERC presentation, we would begin with 13 NRC. And just kind of informally, I would ask if any of you want to jump 14 in. Commissioner Baran?
15 NRC COMMISSIONER BARAN: Great. Thanks for 16 the presentation, Mark.
17 On EMP, the Task Force, is it focused purely on high 18 altitude nuclear EMP or are you looking at geomagnetic storms and other 19 similar phenomena?
20 MR. LAUBY: We took on the GMD topic a couple of 21 years ago. And actually now, thanks to the help with working with FERC 22 and FERC staff, we have two standards in place for GMD.
23 NRC COMMISSIONER BARAN: Okay.
21 1 MR. LAUBY: And I hate to conflate EMP and GMD 2 because the characteristics are different. It's more than a fine point 3 difference. GMD kind of rolls on for a while and has a certain wave front, 4 and EMP has a bit of a different, shorter wave front, even though it's an 5 E3.
6 But we have two standards, one that says, operating, if 7 you get a warning, how do you pre-position the system? And the second 8 one is how you plan the system, so that you can be more robust. How 9 do you identify your vulnerabilities, to what level, and then, what kind of 10 mitigations are you going to put in place?
11 NRC COMMISSIONER BARAN: So here, you're 12 focused really more on manmade?
13 MR. LAUBY: That's right.
14 NRC COMMISSIONER BARAN: Okay. And is the 15 Task Force -- I know you mentioned EPRI -- is the Task Force conducting 16 its own vulnerability assessments or is it considering assessments 17 produced by others?
18 MR. LAUBY: We certainly have looked at the ongoing 19 research. This is an area that does have -- this is an area where there's 20 a lot of speculation, I'll say. And so, we have looked at the different 21 reports that are out there, including those from the Air Force, certainly 22 Oak Ridge. And we also look at EPRI's research.
23 When it comes to vulnerability assessments, the real
22 1 question is, how do you do them? When you're looking at a substation, 2 how do you that vulnerability and risk assessment, so you can understand 3 what mitigations make sense? So, I think that will be one of the next 4 steps here, is how to do that.
5 NRC COMMISSIONER BARAN: Okay. And is it 6 focused mostly on transmission or are you looking at generating assets?
7 Are you looking at nuclear power plants?
8 MR. LAUBY: Currently, right now, we're looking at the 9 transmission assets because that's as far as the research takes us.
10 NRC COMMISSIONER BARAN: Okay.
11 MR. LAUBY: But I know that they're doing two things 12 at EPRI. One is looking at different mitigation strategies. And second of 13 all, they're looking at the generating plants. Third, they've got to get the 14 distribution, because, I mean, I don't know where the load is going to be 15 at at this point.
16 NRC COMMISSIONER BARAN: Uh-hum.
17 MR. LAUBY: You know, what's the impact on cell 18 phones and homes and commercial operations when they're faced with 19 this kind of wave front.
20 NRC COMMISSIONER BARAN: Okay. Great.
21 Thank you.
22 MR. LAUBY: Thank you.
23 NRC CHAIRMAN SVINICKI: Thank you very much.
23 1 Any others? Yes, Commissioner Caputo?
2 NRC COMMISSIONER CAPUTO: So, you mentioned 3 research that is being done at EPRI and perhaps within the military. Are 4 you doing your own research as well or are you simply garnering lessons 5 from the other research going on?
6 MR. LAUBY: Mostly garnering results from others, 7 because EPRI doesn't -- I used to work at EPRI. That's a mind slip 8 there. NERC doesn't do research itself, but we'll fund research. Like 9 we have funded research on GMD or on minimum voltage requirements, 10 and that kind of thing. But we don't do research directly ourselves, 11 though we do tap subject matter experts from across industry who are 12 able to develop very keen models and simulation tools. But we're not 13 doing it ourselves.
14 NRC COMMISSIONER CAPUTO: Okay. Thank you.
15 NRC CHAIRMAN SVINICKI: Commissioner Wright, 16 did you have any questions for this presentation?
17 NRC COMMISSIONER WRIGHT: May I talk to the risk 18 report for a minute?
19 MR. LAUBY: Sure.
20 NRC COMMISSIONER WRIGHT: Although it's not 21 about something that you've talked about really here, the report also talks 22 about some of the challenges associated with staffing.
23 MR. LAUBY: With? I'm sorry?
24 1 NRC COMMISSIONER WRIGHT: With skilled 2 workers.
3 MR. LAUBY: Yes.
4 NRC COMMISSIONER WRIGHT: Yes. And given the 5 turnover in the industry, you know, we're kind of experiencing the same 6 thing. What actions, if you can talk about it, are you taking to mitigate 7 the loss of this expertise and the knowledge loss that's out there? And I 8 guess are there any lessons learned from your end that you could share 9 with us?
10 MR. LAUBY: Well, that's a good question. We have 11 been reaching out to universities, and I'll spend time myself going to 12 promote the power industry. I think a lot of the electric utilities are doing 13 that more and more as well.
14 So, I see it a couple of ways. One is spend time with 15 the universities, and even go in deeper. My daughter just started at 16 Georgia Tech, and I've been working with her to get to engineering most 17 of her life, because you stay on math, right? Sometimes teachers don't 18 know what the math is going to be used for, you know, see how practical 19 it is.
20 So, working with the schools and universities, and then, 21 also, bringing in co-op students and student engineers, even if they 22 haven't really picked the power program, because I'm thinking of it from 23 an engineering perspective, because that's how I got turned into energy,
25 1 was a power company, Northern States Power said, "Yeah, why don't you 2 come work for us for a summer?" And then, I stayed with it for the rest of 3 my career. So, I think making sure you're tight with the educational 4 system I think will help a great deal.
5 NRC COMMISSIONER WRIGHT: Is there an area 6 within -- because you're in various levels throughout -- but is there an 7 area that concerns you more than another?
8 MR. LAUBY: My concern mostly has been the skill 9 sets.
10 NRC COMMISSIONER WRIGHT: Right.
11 MR. LAUBY: This is not your grandfather's or 12 grandmother's engineering anymore. You have to worry about cyber and 13 building that into your designs. Well, how many people coming out of 14 school in power systems know anything about cyber systems, right? So, 15 I'm really concerned about the skill sets that we're getting people ready to 16 help us support the system of the future. Communications, the interplay 17 between multiple sectors -- gas, electric, communications, water -- getting 18 that understanding.
19 NRC COMMISSIONER WRIGHT: Thank you so much.
20 NRC CHAIRMAN SVINICKI: Thank you.
21 Before I turn it over to Chairman Chatterjee, maybe I'll 22 just have one question for you, Mark. You mentioned the new 23 technologies are coming at you pretty fast and the need to really have
26 1 high-fidelity modeling and simulation. I know that the Department of 2 Energy National Laboratories, of course, have been funded to do 3 extensive modeling of energy systems and things. Does NERC draw on 4 that? Or do you have kind of centers of competencies or excellence on 5 the modeling and simulation for the electrical grid system?
6 MR. LAUBY: Yes, we've been working really close 7 with DOE and Bruce Walker. We're waiting for the NARMS model to 8 come out. In fact, we have assigned one of our staff just basically 9 full-time to work with the DOE on the NARMS model itself. So that, when 10 it comes out, it's something we're going to find useful. And the way I 11 understand it, I should be getting that model in five days, is what I've been 12 told, the end of the third quarter. And that will be a starting point, 13 steady-state gas-electric interplay. And then, once they state that, that 14 means ending up putting the dynamics in there. And then, the next step, 15 I guess, is to take and put dynamics in there, as well as cyber systems.
16 Now we're getting multiple systems. So, we are working closely with 17 Bruce Walker and his team over there at DOE.
18 NRC CHAIRMAN SVINICKI: Well, thank you very 19 much. And you obviously are eagerly anticipating it if you have a day 20 clock going.
21 MR. LAUBY: I'm looking forward to it.
22 NRC CHAIRMAN SVINICKI: So, I hope they get you 23 what you need on time.
27 1 Chairman Chatterjee, please.
2 FERC CHAIRMAN CHATTERJEE: Thank you, Mark, 3 for that excellent presentation and the great work that you and the folks at 4 NERC do.
5 I just wanted to briefly touch on what you raised about 6 the attention that NERC is paying to inverter-based resources. And I just 7 wondering if you could elaborate on where NERC is with that work and 8 how it may translate into concrete action for industry and government?
9 MR. LAUBY: Yes. Well, it's, again, another good 10 question. As soon as we found out about this issue with all the 11 photovoltaic resources coming offline, we spun up a quick task force, 12 which included manufacturers; organizations in the West; our regional 13 partner there, WECC, and just kind of got quickly to the bottom what the 14 issues were. And then, we formalized that into what we call the 15 Inverter-Based Resource Task Force, which now I think we're going to 16 promote to subcommittee. The difference between the two is that one 17 has longevity and one just gets wound up at the end.
18 And during that, its time right now, a couple of things 19 have happened. They've created a SAR, so we can improve the 20 standard, PRC-24. They've had about four guidelines, one on modeling, 21 one on how you simulate, one on how you might adjust the controls.
22 And there's over 100 people on this. So, I think there is a great deal of 23 interest.
28 1 And why? Because it's not only going to be impacting 2 our photovoltaic resources, but battery resources used, as you know, 3 inverters. Anything that creates DC current or DC voltage has to be 4 converted to AC. So, even wind uses a lot of inverters. So, we need to 5 get this right, and working with manufacturers, some of which are in 6 Europe as well as here in North America, making sure that 7 they -- because they want their designs to work. They want them to be 8 there to support the system.
9 And then, understanding what's the impact on the 10 system when you have these asynchronous resources which are kind of 11 separated. You know, the heft is kind of separated from the system by 12 these inverters. And understand the impacts and frequency response.
13 So, we're also, then, going through and simulating those with the industry.
14 So, I think the action is being taken. The adjustments 15 are being made on the photovoltaics. We know that. We're going to 16 follow up with them, make sure that it's all been done.
17 WECC is working with each one of those, looking at 18 PRC-24 and saying and wondering if they were following that to the "T".
19 Because momentary cessation versus tripping, what's the difference?
20 So, yes, we have that kind of a vernacular. But, yes, we're working on it, 21 yes.
22 FERC CHAIRMAN CHATTERJEE: Thank you.
23 NRC CHAIRMAN SVINICKI: Commissioner Glick?
29 1 FERC COMMISSIONER GLICK: Thank you.
2 So, Mark, you mentioned the after-action review and 3 that you're doing it with regard to Texas, given the experience this past 4 summer and the summer before where they had a low reserve margin, 5 but they managed to keep the lights on.
6 I'm wondering -- and I know that you're probably looking 7 at this in the review -- do we need to think about reliability a little bit 8 differently, especially reserve margins? Do we need the excessive, you 9 know, the substantial reserve margins in some of the regions, or newer 10 technologies and newer techniques, is that really alleviating some of the 11 need for high reserve margins?
12 MR. LAUBY: I always think of reserve margins as 13 really a multi-dimensional metric, not just 10 percent, 15 percent. So, I 14 think you put your finger on something that's very interesting. We've 15 been looking at California, Texas, and New England, and saying, what's 16 happening there and how are they getting through?
17 And one of the answers appears to be energy. And 18 how do you make sure you plan a system that has enough energy, not 19 just reserve margins, but energy. Because the way Texas is getting 20 through is they've got a certain kind of price-responsive loads. So, when 21 the price gets high, they come off, and that's helped them. That's kind of 22 built in, you might say, an additional amount of energy reserves, you 23 might say.
30 1 So, I think that's one of the reasons why we're also 2 interested in this tool that DOE is creating, because we can put a time 3 component on it and start calculating energy needs, and are there ways 4 in which we can start thinking about building a system with a sufficient 5 amount of energy at all times to serve the energy needs of the system.
6 And that takes you away from this, because there's a lot of assumptions 7 in reserve margins. There's assumptions of fuel availability and 8 assumptions on the reliability of the equipment. And this helps us kind of 9 walk a little bit, step away from that, and really kind of get down to what 10 my boss called the "secret sauce". So, yes.
11 FERC COMMISSIONER GLICK: Thank you.
12 NRC CHAIRMAN SVINICKI: Thank you.
13 Commissioner McNamee?
14 FERC COMMISSIONER MCNAMEE: In the 15 presentation you demonstrated where there's been problems in 16 transmission. So, it's historical data that tells you where the problems 17 have been, which, then, rightly so, you want to invest money or you want 18 to invest in creating a standard to address that. How does NERC 19 approach dealing with high-impact, but low-frequency events to make 20 sure that we're focused on things that may not be showing up, but if they 21 do show up, they're going to have some dramatic impact?
22 MR. LAUBY: Sure. And, of course, I would say the 23 GMD would be one of those. I would say EMP would be one of those,
31 1 right, those high impact, cyber-attack. We've been fortunate in not 2 having something that's widespread, but we stay in front of those.
3 And so, it's one of those things where I think it's 4 mentioned in the risk report they look forward; they try to identify some of 5 those potential high-impact events, even if we haven't experienced them 6 yet, and make sure we have measures in place, be they through 7 guidelines; if it makes sense, through a standard, to address them.
8 In my mind, it all comes down to the four quadrants.
9 High impact, high likelihood, better have a standard there. High impact, 10 low likelihood, maybe you want a standard there. Highly likely, but no 11 impact, probably guidelines that are low impact. And so, you kind of go 12 through the four quadrants. I've lost track.
13 But we're actually putting together a white paper on this 14 because we want to have a conversation with industry about when is a 15 standard appropriate, and not the conversation of -- the only answer is 16 not a standard. I mean, not all things need standards. I get that. But 17 what things do need standards, and make sure we have a conversation 18 with industry about it, yes.
19 NRC CHAIRMAN SVINICKI: Thank you very much.
20 Next, we will hear presentations from two of the FERC 21 staff. First, we will hear from Mr. David Huff, who is an electrical 22 engineer in the Office of Electrical Reliability. And next, I'm going to 23 apologize because on our scheduling notice we have Mr. Anuj -- it's
32 1 spelled Kapadia, but I note your nameplate is different. So, my 2 apologies, and I'm no stranger to having my name misspelled. But I 3 really apologize for that.
4 (Laughter.)
5 But he is an electrical engineer with the Office of 6 Electric Reliability, and he will give the second FERC presentation.
7 And again, please, if you would, would you pronounce 8 your name correctly? Which of the two is correct?
9 MR. KAPADIA: It's Anuj, Anuj Kapadia. Thank you.
10 NRC CHAIRMAN SVINICKI: Okay. Thank you very 11 much.
12 And we will begin with Mr. Huff.
13 MR. HUFF: Thank you, and good morning, Chairman 14 Svinicki, Chairman Chatterjee, and Commissioners.
15 I will provide you an overview of the 2019 FERC and 16 NERC staff report on the South Central United States Cold Weather Bulk 17 Electric System Event of January 17, 2018.
18 Next slide, please.
19 I am with FERC's Division of Compliance in the Office of 20 Electric Reliability. The Division's role is to monitor the compliance of the 21 users, owners, and operators of the bulk power system with reliability 22 standards through audits as well as through analyses and investigations 23 concerning events on the bulk power system.
33 1 And we'll just hold on that slide there.
2 The inquiry which led to the report arose out of two 3 presentations describing the January 17, 2018, event to FERC staff, one 4 by the Midcontinent Independent System Operator, or MISO, and the 5 other, a combined presentation by Southwest Power Pool, or SPP; 6 Tennessee Valley Authority, or TVA, and Southeastern Reliability 7 Coordinator, or Southeastern RC, represented by Southern Company, as 8 well as other joint parties to a settlement agreement between MISO and 9 SPP; namely, Associated Electric Cooperative, Louisville Gas & Electric, 10 Kentucky Utilities, and Power South.
11 Following these presentations, the Commission and 12 NERC announced a joint inquiry with the regional entities, siting, among 13 other factors, reports of multiple forced generation outages, voltage 14 deviations, and near-overloads, and the need to understand and 15 underscore the importance of seamless Reliability Coordinator, or RC, 16 interactions.
17 Next slide, please.
18 The event occurred on January 17, 2018, when a large 19 area of the South Central Region of the United States experienced 20 unusually cold weather due to an Arctic high pressure system moving 21 from the Northern Plains to the Central and Eastern U.S., which was 22 forecast several days in advance. This resulted in average temperatures 23 dropping well below freezing, with temperatures up to 28 degrees
34 1 Fahrenheit below normal.
2 Next slide, please.
3 Between January 15 and January 19, the 4 below-average temperatures in this area resulted in a total of 183 5 individual generators experiencing either an outage, a derate, or a failure 6 to start. By the start of January 17th, morning peak hour, counting the 7 already planned and unplanned outages, the four RCs had over 30,000 8 megawatts of generation unavailable in the South Central United States 9 portions of their footprints. This was approximately 25 percent of the 10 generating capacity in the event area.
11 Next slide, please.
12 While the significant unplanned outages and derates of 13 generators in the event area was the primary cause of the event, several 14 other factors contributed to the bulk electric system conditions faced by 15 system operators the morning of January 17, including the increased 16 electricity demand.
17 Most of the affected entities' peak electricity loads 18 exceeded their forecast 2017-2018 winter peak loads. Further, the peak 19 loads for the SPP footprint and the MISO South Region broke previous 20 winter peak records and neared MISO South's all-time summer peak 21 demand.
22 Also, MISO's Regional Directional Power Transfer, or 23 RDT, sourced from MISO's generation reserves in their northern area,
35 1 was used to help cover their record winter electricity demand and 2 unavailable generation in MISO South. The RDT suddenly increased in 3 a north-to-south direction, affecting the RC footprints of MISO, SPP, TVA, 4 and Southeastern RC. The RDT reached a measured maximum of 5 4,331 megawatts, exceeding MISO's and SPP's agreed-upon limit of 6 3,000 megawatts.
7 Further, remote generation power transfers, including 8 MISO's and SPP's dispatch of wind generation and power transfers 9 between SPP and ERCOT Interconnection, contributed to the bulk 10 electric system conditions faced by system operators that day.
11 Next slide, please.
12 As a result of the unavailable generation of MISO 13 South, MISO declared an energy emergency because it had insufficient 14 reserves to balance generation and load in MISO South's portion of its 15 footprint, where it initiated voluntary load reduction. In addition, all four 16 of the RCs experienced constrained bulk electric system conditions 17 across portions of their footprints spanning all or parts of nine states.
18 Next slide, please.
19 A comparison of below-freezing temperatures and 20 unplanned generation outages and derates in the event area from 21 January 15th to 19th indicated a correlation between generation outages 22 and cold temperatures, meaning that, as temperatures decreased, 23 unplanned generator outages and derates increased. For this
36 1 timeframe, of the 44 percent of the unplanned outages and derates that 2 were related to extreme cold weather, 14 percent were directly attributed 3 by the generator owners to weather-related causes, including frozen 4 sensing lines, frozen water lines and valves, and low-temperature cutoff 5 limits. The other 30 percent were indirectly attributable to weather, 6 including mechanical causes known to be related to cold weather and gas 7 supply curtailments to natural-gas-fired generators.
8 Gas supply issues caused by extreme cold 9 temperatures, including interruptible supply, low gas pressure, and other 10 pipeline and gas supply issues, led to outages of 38 units, for a total of 11 approximately 2,200 megawatts. Also, the team found that one-third of 12 the generator owner-operators did not have winterization procedures, and 13 temperatures in the area where the cold weather event occurred were 14 generally above the ambient temperature design specifications for many 15 natural-gas-fired generating units.
16 Next slide, please.
17 The relevant RCs -- MISO, SPP, TVA, and 18 Southeastern RC -- had situational awareness throughout the event and 19 communicated as necessary to preserve system reliability. The RCs 20 were regularly performing assessments to determine the next courses of 21 action. MISO issued energy emergency alerts, purchased emergency 22 energy, and implemented voluntary load-reduction measures.
23 MISO South's reserves were down to 172 megawatts
37 1 for the morning peak hour ending 8:00 a.m. Central Time, and if the next 2 worst single generator contingency of 1163 megawatts in MISO South 3 occurred, it would have likely resulted in firm load shed to maintain 4 generation and load balance, while simultaneously triggering further and 5 additional firm load shed in specific areas of the MISO South footprint to 6 maintain bulk electric system voltages within limits.
7 Next slide, please.
8 The report identifies 13 recommendations to improve 9 bulk electric system reliability. For generator cold weather reliability, the 10 team recommends a three-pronged approach, including development or 11 enhancement of NERC reliability standards, enhanced outreach to 12 generator owner-operators, and market rules, where appropriate, to 13 address the following needs:
14 The need for generator owner-operators to perform 15 winterization activities to prepare for adverse cold weather, including 16 implementing freeze protection measures, along with adequate 17 maintenance and inspection of freeze protection elements; 18 And gas-fueled generating units clearly informing their 19 RC and balancing authority whether they have firm transportation 20 capacity for the natural gas supply; 21 And the need for generator owner-operators to ensure 22 the accuracy of the generating plants' ambient temperature design 23 specifications and share these with the RCs and balancing authorities.
38 1 Next slide.
2 Finally, the need for RCs and balancing authorities to 3 be aware of the specific generating units' limitations, such as ambient 4 temperatures beyond which they cannot be expected to perform, and take 5 these limitations into account in their operating processes.
6 Next slide.
7 The other 12 recommendations pertain to transmission 8 reserves, which include:
9 Recommending RCs should perform real-time voltage 10 stability analysis, in addition to real-time contingency analysis, or RTCA, 11 for constrained conditions occurring within their own or within adjacent 12 RC areas, such as those experienced by MISO the morning of January 13 17, and communicate the results of the analysis to adjacent RC areas.
14 Real-time voltage stability analysis could assist the RCs in determining if 15 other mitigation actions are necessary, as well as whether an emergency 16 condition exists.
17 Next slide.
18 Also, recommendations include:
19 Jointly developing seasonal transmission studies and 20 simultaneous power transfer studies to be better prepared for seasonal 21 extreme conditions; 22 Balancing authorities considering deliverability of 23 reserves to avoid stranded reserves;
39 1 And improving load forecasts for extreme days such as 2 January 17, 2018.
3 Next slide.
4 This concludes staff's comments, and following the next 5 presentation by Anuj, I will be happy to answer any questions you might 6 have. Thank you.
7 NRC CHAIRMAN SVINICKI: Thank you.
8 Anuj, please proceed.
9 MR. KAPADIA: Thank you, Dave.
10 Good morning, Chairman Chatterjee, Chairman 11 Svinicki, and the Commissioners. My name is Anuj Kapadia, and I am 12 an electrical engineer working in the Office of Energy Infrastructure 13 Security, recently transferred from the Office of Electric Reliability.
14 Next slide, please. Next slide.
15 Today, I will be presenting on FERC's Order 841, 16 Electric Storage Participation in Markets Operated by Regional 17 Transmission Organizations, RTOs, and Independent System Operator, 18 ISOs; and will also give an overview of the electric storage resources.
19 Next slide. Next slide.
20 On November 17th, 2016, the Commission issued a 21 Notice of Proposed Rulemaking, NOPR, proposing to require each 22 RTO/ISO to revise its tariff to establish a participation model consisting of 23 market rules recognizing the physical and operational characteristics of
40 1 electric storage resources and which accommodates their participation in 2 the wholesale markets. The NOPR also proposed new market rules to 3 allow distributed energy resource aggregators to participate directly in the 4 wholesale organized markets.
5 Next slide, please.
6 In February 2018, the Commission issued a Final Rule 7 requiring RTOs/ISOs to establish a participation model ensuring electrical 8 storage resources are eligible to provide all capacity energy and ancillary 9 services they are technically capable of providing. The Final Rule 10 proposed the following:
11 RTO/ISO tariffs should include bidding parameters that 12 reflect the physical and operational characteristics of electric storage 13 resources.
14 Electric storage resources be able to be dispatched and 15 set the wholesale market clearing price as both a wholesale seller and 16 wholesale buyer.
17 RTO/ISO tariffs establish a minimum-sized requirement 18 for electric storage resources not to exceed 100 kilowatts.
19 And last, electric storage resources be able to pay the 20 wholesale price for charging energy that they resell back into the 21 wholesale markets.
22 Next slide, please.
23 Regarding the DER aggregation and the Final Rule,
41 1 actually, the Commission recommended that more information was 2 needed and did not take final action in the Final Rule establishing new 3 separate proceedings.
4 In February of 2018, Order 841 was issued. In 5 December of 2018, the entities filed their compliance filing with the 6 Commission. Staff is currently reviewing them and will provide direction 7 back to the RTOs/ISOs.
8 Next slide, please. Next slide.
9 Order 841 defined electric storage resources as a 10 resource capable of receiving electric energy from the grid and storing it 11 for later injection to the electric energy back to the grid.
12 An electric storage resource has bidirectional electric 13 and storage capabilities and is characterized by both power capacity, 14 which is megawatts, and energy capacity, which is megawatt per hour.
15 Next slide, please.
16 This slide shows a few examples of electric storage 17 technologies. The difference between the first two type of batteries, 18 which are solid-state and flow batteries, is that the conventional batteries 19 store energy in a solid electrode system, while the flow batteries rely on 20 storing charge in at least one liquid. Examples of solid-state include 21 lithium ion, solid sulfur, lead acid, and nickel cadmium batteries.
22 Flywheels store energy kinetically with spinning rotor.
23 The compressed air energy storage utilizes compressed air to create an
42 1 important energy reserve. Pumped hydro, which charges large-scale 2 reservoirs of energy with water, and lastly, advanced rail energy storage 3 stores energy by raising the elevation of mass against the force of gravity 4 and recovers the stored energy as the mass is returned back to the 5 original location.
6 Next slide, please.
7 This slide shows a few examples of storage projects.
8 The first one was a gas leakage at the Aliso Canyon facility which 9 resulted in constraint to the grid. The solution for this was three large 10 storage projects totaling to 70 megawatts and 280 megawatt-hours.
11 The second was a project of PG&E, replacing three gas 12 plants with 568 megawatts of storage capacity. This project is scheduled 13 to be completed and to come online by the end of 2020.
14 The third is a hybrid project of 100 megawatts of 15 storage in SoCal Edison. This is a project which is combined with 1284 16 megawatts of a gas-fired plant. Commercial operation for this project is 17 scheduled to be 2021.
18 The last is a proposed pumped hydro project in Arizona 19 totaling to 2,000 megawatts. This project is scheduled to be online 20 between 2025 and 2028.
21 Next slide, please.
22 This slide shows U.S. utility scale battery storage power 23 capacity as of March 2019. The two largest operating utility scale battery
43 1 storage sites in the United States as of March 2019 provide 40 2 megawatts of power capacity each.
3 In the U.S., 16 operating battery storage sites have 4 been installed with a power capacity of 20 megawatts or greater. As of 5 March 2019, the total current operating utility scale battery storage is 889 6 megawatts, and planned to come online through 2023 is 1623. If these 7 planned facilities come online as scheduled, total U.S. utility scale battery 8 storage power capacity would nearly triple by the end of 2023. The 9 largest two sites account for 725 megawatts and are planned to start 10 commercial operation in 2021, which is why you see the spike in the 11 2021.
12 Next slide, please.
13 This slide shows a breakdown of operating battery 14 storage by state. Of the 889 megawatts of installed operating battery 15 storage reported by states as of March 2019, California, Illinois, and 16 Texas account for less than half of the storage capacity.
17 Next slide, please.
18 Storage business cases are currently built on 19 generating revenue streams by providing services to the wholesale 20 markets or other customers, such as utilities or retail customers, or being 21 used to avoid investment in more costly infrastructure. The ability to 22 provide multiple services potentially to multiple entities has long been 23 touted as the "secret sauce" of electric storage resources. Removing
44 1 technical and regulatory barriers to be able to engage in multiple-use 2 applications will help unlock more value for the energy storage resources.
3 Next slide, please.
4 Bulk battery storage capacity continues to grow, driven 5 by state-led policies and rapid cost decreases. State mandates will drive 6 near-term storage investments. Longer-term cost decreases in lithium 7 ion and other battery technology will likely lead battery storage to be 8 increasingly cost competitive. Lastly, additional cost savings may come 9 from pairing of solar and battery storage projects.
10 This concludes my presentation, and I'm happy to take 11 any questions you may have.
12 NRC CHAIRMAN SVINICKI: Well, thank you both for 13 those presentations.
14 For the FERC presentations, we will begin once again 15 with questions from the NRC Commissioners. Does anyone want to 16 jump in? Commissioner Baran? Thank you.
17 NRC COMMISSIONER BARAN: Thanks.
18 I have a question on cold weather, and then, one on 19 electric storage. On cold weather, the NRC has regulations requiring 20 nuclear power plants to have procedures to prepare for cold weather or 21 winter storms. And we actually inspect those procedures. I'm trying to 22 get a sense of what the situation is for non-nuclear generating assets.
23 Do they have similar winterization procedures and are there standards
45 1 governing those winterization procedures?
2 MR. HUFF: Currently, there are no requirements for 3 winterization for the non-nuclear generators or for generation in the 4 reliability standards.
5 NRC COMMISSIONER BARAN: Is it pretty common, 6 though, that they have formal winterization procedures?
7 MR. HUFF: What the team found as far as for the area 8 that was affected by this event, the team found that one-third of the 9 generator owner-operators did not have winterization procedures, which 10 two-thirds, they did find that they did have procedures for winterization.
11 NRC COMMISSIONER BARAN: And do you have a 12 sense? Is that something that differs, depending on kind of the 13 geographic area of the country? Is it more common to have winterization 14 procedures up north and less common down south, where this occurred?
15 MR. HUFF: The team didn't analyze outside of the 16 event area, but the team did analyze -- and it's included in the 17 report -- some differences and it provides an understanding of the 18 differences between the northern and southern construction of generating 19 units. And what's found in kind of the southern areas of the United 20 States, there's open-frame construction for generators that, as long as 21 they would have freeze protection measures in place when the 22 temperature dropped, that would help prevent the freezing, but they're 23 exposed in more the southern areas versus the northern, where the
46 1 generators have an enclosed generator design inside buildings.
2 NRC COMMISSIONER BARAN: All right. Thank you.
3 And in terms of the market experience with electric 4 storage, I know this is going to be very market-specific, but is there kind 5 of any general statements that can be made about the effect electric 6 storage has on wholesale electricity prices during the day versus at night?
7 Does it generally reduce them during the day and increase them at 8 night? I'm trying to understand how more electric storage capacity would 9 affect the revenue of nuclear power plants that generate electricity 10 throughout the night when demand is low.
11 MR. KAPADIA: I would say the storage can be used, 12 say, for example, by a nuclear plant to actually store energy when you 13 don't have that much of a load, and then, use it the next day. And that's 14 why I think the whole system cost would reduce overall.
15 NRC COMMISSIONER BARAN: Okay. And do you 16 have a sense of, you know, if we're talking about nuclear generating 17 units, the kind of overall effect it has on their revenue from wholesale?
18 MR. KAPADIA: I don't have the costs per se, but I 19 would assume it would go down.
20 NRC COMMISSIONER BARAN: Thank you.
21 NRC CHAIRMAN SVINICKI: Thank you.
22 Other members of the NRC? Commissioner Caputo?
23 NRC COMMISSIONER CAPUTO: Hi. I'd like to just
47 1 take Commissioner Baran's question a little bit further in terms of 2 winterization procedures. How close was the correlation between the 3 generation sources that were lost with the lack of winterization 4 procedures? Was there a direct correlation or were there cases where 5 they had winterization procedures and they were still ending up in a 6 shutdown?
7 MR. HUFF: The team did not analyze that relationship 8 where winterization procedures didn't exist as far as how that impacted 9 that availability of that generator. But what the report contains 10 information on, and what we did analyze, was that there is a 0.7 11 correlation between temperature decrease and the unavailability of the 12 generation in the event area. So, that was the level that we focused on.
13 NRC COMMISSIONER CAPUTO: So, there may be 14 situations where generators had procedures and followed their 15 procedures and they still came off, and vice versa?
16 MR. HUFF: Yes, or -- yes.
17 NRC COMMISSIONER CAPUTO: Where they may 18 not have had winterization procedures, but they did stay on?
19 MR. HUFF: Yes. Yes.
20 NRC COMMISSIONER CAPUTO: Okay. Thank you.
21 NRC CHAIRMAN SVINICKI: Thank you.
22 Commissioner Wright?
23 NRC COMMISSIONER WRIGHT: Thank you so much.
48 1 David, I like your name, by the way.
2 (Laughter.)
3 You know it does mean "beloved" in the Hebrew.
4 So, let me ask you a question about the generator 5 owner-operators thing. How likely are they to implement your 6 recommendations? Do you have a sense?
7 MR. HUFF: Well, for the first recommendation, it's a 8 recommendation for a three-pronged approach, which one is a 9 recommendation for a standard to be developed, which it's a process 10 that's been established under the nuclear reliability standards, and NERC 11 leads that. So, that will be a process where there will be a proposal for a 12 standard, or a standards authorization request is the starting point. And 13 then, that will be an industry-driven process to move that forward and to 14 come up with the right language for the standard. So, the generator 15 owner-operators are stakeholders in that process. So, they can weigh-in 16 on the development of that standard, so that it's the appropriate approach 17 there.
18 The other two approaches, market rules, the RTOs, the 19 Regional Transmission Organizations, and the Independent System 20 Operators, they may come up with protocols and have those established 21 that the generator owner-operators to be part of that market, and would 22 then need to follow those protocols to be participating in that market. So, 23 that one would be driven from the ISO/RTO end.
49 1 So, there are some voluntary aspects to the generator 2 owner-operators moving this forward and what the team is 3 recommending, but the standard is one of the approaches that is a 4 backstop in the sense to establish winterization steps.
5 NRC COMMISSIONER WRIGHT: So, if we continue to 6 see what appears to be a lot of record-breaking seasonal changes right 7 now, do you expect future generation outages, even if all the 8 recommendations were put into place? And if so, what type of other 9 potential remedies do you foresee or are you considering?
10 MR. HUFF: Well, the team, with the recommendations 11 that are in the report, the goal is that they would remediate or they would 12 alleviate those conditions. So, those generators that would take those 13 steps to winterize would, then, be available. The other component of 14 that is that the generator may elect not to winterize, but at least they are 15 making their design specification and what they've implemented at their 16 plant accurate, and they're communicating that to the Reliability 17 Coordinator and balancing authorities, so that they know that the 18 generator won't be available during those cold weather times.
19 So, I think that all of those steps in place will help 20 alleviate the event, the conditions that were experienced during this 21 event.
22 NRC COMMISSIONER WRIGHT: I've got one more 23 question. And I kind of want to understand the hot and cold thing a little
50 1 bit more. So, what kind of increase in failures or stress and grid reliability 2 do you see related to cold weather as opposed to hot weather? And how 3 are hot weather grid reliability actions, how are they similar or how do 4 they differ from those of cold?
5 MR. HUFF: If I understand your question, our team 6 was focused on looking at the event, and this was a winter event.
7 NRC COMMISSIONER WRIGHT: Right, right.
8 MR. HUFF: So, generators, you know, for what we're 9 talking about, not having freeze protection measures is an issue in the 10 winter --
11 NRC COMMISSIONER WRIGHT: Right.
12 MR. HUFF: -- but wouldn't necessarily be an issue at 13 all as far as making sure that those units are available in the summer.
14 They're going to have to have enough ventilation, and so forth, to be 15 available, so that they can operate those units to their full capability 16 during the summer. So, that would not come into play there. The team 17 was focused really looking at the winter, the winter issues.
18 NRC COMMISSIONER WRIGHT: Fair enough.
19 Thank you.
20 NRC CHAIRMAN SVINICKI: Well, thank you both for 21 the presentation. And everyone's questions were so precise. So, I was 22 kind of sitting here thinking about the benefit of these meetings 23 sometimes is that we can explore our intellectual curiosity. I also have a
51 1 take-away from all of these meetings where my feeling is I'll take the 2 simplified problem set of nuclear safety and security regulation over what 3 my colleagues at the FERC have to deal with.
4 (Laughter.)
5 I have that feeling. It's like that I think Greek mythology 6 where everyone lays their issues out on the table and you'll happily take 7 your own set of problems back and let everyone take their set.
8 But I had an opportunity this summer -- so this is about 9 electric storage -- to visit with some folks who run, well, we used to call 10 them "server farms". I don't know. Are they data centers? So, it's the 11 cloud. You know, it's the people running these facilities that have such 12 huge power needs.
13 But something I hadn't thought about is their incredibly 14 rigorous demand for power quality and reliability, because they have 15 everyone's iPhone photos and things we can't live without. But they are 16 really, obviously, investing a lot in R&D on storage.
17 And so, when the presentation mentioned that we do 18 forecast perhaps that we will continue to see this kind of rapid adoption or 19 investment in storage capacity here in the United States, is it truly that the 20 technology of storing the energy, is there a cost decrease in that that's 21 rapid in the same way that, you know, photovoltaics and things have just 22 seemed kind of almost leapfrogs of technology innovation and 23 cost-effectiveness? Is it a bunch of things working in concert? But is
52 1 the technology itself just becoming cheaper?
2 MR. KAPADIA: The technology is definitely getting 3 cheaper. From what I understand, between 2010 and 2018, the average 4 cost of lithium ion batteries, which are widely used right now, has fallen by 5 85 percent.
6 NRC CHAIRMAN SVINICKI: Wow.
7 MR. KAPADIA: And according to Bloomberg Energy 8 Finance, a research firm forecast that the cost will continue to fall by 9 another 45 percent by 2024. So, it's definitely getting cheaper.
10 NRC CHAIRMAN SVINICKI: So, as you all look at 11 these issues, I assume, then, you're kind of preparing yourself for an 12 overall portfolio of assets in the U.S. system that would have a greater 13 and greater degree of energy storage? I know some of these data 14 centers also, you know, they want to be selling some power back into the 15 system. So, it gets to a very complicated, multi-variable equation, but it's 16 another change dimension that it seems like the FERC analysts have to 17 kind of build into their models and be thinking about its systemwide 18 effects.
19 MR. KAPADIA: Absolutely.
20 NRC CHAIRMAN SVINICKI: Which should be 21 advantageous, I would think. I mean in terms of the overall system.
22 MR. KAPADIA: It can be used as a generator and can 23 be used as a load. So, it's definitely an advantage for the system.
53 1 NRC CHAIRMAN SVINICKI: Okay. Thank you very 2 much.
3 I'll turn it over to Chairman Chatterjee.
4 FERC CHAIRMAN CHATTERJEE: Thank you, 5 gentlemen, for those excellent presentations and all the good work that 6 you do on these projects.
7 I've been very bullish on storage because it can provide 8 many services. One of the possible uses that has been proposed for 9 storage is in system restoration from a black-start condition. Obviously, 10 one critical element of black-start is getting offsite power back to nuclear 11 facilities as quickly as possible. How could the use of storage help a 12 utility during black-start operations? And have we seen any utilities or 13 RTOs moving to integrate the use of storage into their black-start plans?
14 MR. KAPADIA: I am not aware of anyone using the 15 black-start as of yet, but that is definitely an application which the industry 16 is looking forward for. It can be used as a cranking part. I mean, you 17 know, when you lose all the generators, when you actually need a 18 cranking part, you can actually just crank up a battery and use it as a 19 cranking part to maybe just open up a generator or turn it on, or 20 something along those lines. So, it can be used as a restoration, but I 21 don't think the industry is using it right now.
22 FERC CHAIRMAN CHATTERJEE: That's very helpful.
23 Another possible application that's been discussed for
54 1 storage is energy arbitrage. In other words, when there's excess 2 electricity and discharging during peak hours, we know that nuclear plants 3 in certain parts of the country have struggled with negative pricing during 4 certain hours. Could the proliferation of storage resources help address 5 some of those issues?
6 MR. KAPADIA: Absolutely. Going back to 7 Commissioner Jeff's question, I think you can store the energy while it's 8 negative, and then, actually use it for the next day, increasing the revenue 9 for the whole system. Actually, decreasing the cost for the system, but 10 increasing the revenue for the resource.
11 FERC CHAIRMAN CHATTERJEE: Thank you for that.
12 Dave, you mentioned that we've had previous cold 13 weather events like this over the last several years. Have we seen any 14 specific performance issues with nuclear generators during these events?
15 And also, I know that, as a result of these events, NERC has developed 16 best practices for generator weatherization. Are those generally 17 applicable to nuclear as well, and if so, how have the operators done in 18 implementing those recommendations?
19 MR. HUFF: As far as nuclear, there's not been seen 20 an issue with the winterization. The issues have been seen in the most 21 recent event here, the January 2018, or January 17, 2018 event was 22 gas-fired generators. They were a large percentage impacted by 23 weatherization.
55 1 As far as practices go, there have been generators that 2 have taken advantage of those best practices that have come out since 3 the 2011 Southwest U.S. event that occurred in February of 2011, and 4 especially the area of ERCOT-Texas, which was one of the areas, a large 5 portion of that 2011 event, and they've implemented some protection 6 measures regarding winterization and have had success there.
7 FERC CHAIRMAN CHATTERJEE: Thank you.
8 NRC CHAIRMAN SVINICKI: Thank you.
9 Commissioner Glick?
10 FERC COMMISSIONER GLICK: Thank you.
11 I just wanted to follow up on Chairman Chatterjee's 12 questions, some of the other questions regarding winterization. But 13 primarily, I'm just curious if you have statistics of what the percentage of 14 the plants, the 25 percent of the plants that were out, how they broke 15 down between gas, nuclear, coal, other technologies.
16 MR. HUFF: Taking gas a little farther, 70 percent of 17 the generators that were unplanned outages during that January 18 15th-to-19th timeframe, 70 percent were natural-gas-fired generators.
19 By megawatts, it was 74 percent of the megawatts that were, of the 20 unplanned outages, derates, or failures to start, were natural-gas-fired 21 generators.
22 FERC COMMISSIONER GLICK: Is that consistent 23 with some of the other cold weather snaps we've seen in the New
56 1 England ISO, for instance, and in MISO North, and so on?
2 MR. HUFF: The team didn't analyze those per se, as 3 far as bringing those into the study and into the report. There have been, 4 talking about the 2011 event, there were gas-fired generators that were 5 impacted in that event and tying that to a lack of winterization.
6 FERC COMMISSIONER GLICK: Okay. Thank you.
7 NRC CHAIRMAN SVINICKI: Thank you.
8 Commissioner McNamee?
9 FERC COMMISSIONER MCNAMEE: Following on 10 Commissioner Glick's question about the natural gas outages, was the 11 cause primarily mechanical? Was it lack of access to gas? What were 12 the causes of those natural gas outages?
13 MR. HUFF: There were several causes. There were 14 ones who had interruptible gas supply. There were some that were 15 impacted by low gas pressure. And those were the major issues. Some 16 related to facilities related to gas that caused the unit to not be able to 17 access the gas supply. So, those were the main areas.
18 FERC COMMISSIONER MCNAMEE: Okay. And 19 then, I wanted to look at slide 10 on the energy storage discussion. And 20 I notice in the various examples on slide 10 of the storage examples, 21 except for pumped hydro, it looks like each of these storage facilities had 22 about a four-hour storage or four hours of energy that they could 23 provide --
57 1 MR. KAPADIA: That is correct. Most of the resources 2 which have been approved and which are on that page I think are four 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />.
4 FERC COMMISSIONER MCNAMEE: Yes. Okay.
5 And are you familiar with basically the average megawatt size for a 6 nuclear facility or a nuclear unit?
7 MR. KAPADIA: I think 1,000-1,200 megawatts.
8 FERC COMMISSIONER MCNAMEE: And that's 9 usually a two-unit facility, right?
10 MR. KAPADIA: Right. Right.
11 FERC COMMISSIONER MCNAMEE: I'll defer to the 12 experts.
13 MR. KAPADIA: Yes.
14 FERC COMMISSIONER MCNAMEE: And do you 15 know what their general capacity factors are? Do they run 24/7? Do 16 they run for --
17 MR. KAPADIA: The storage?
18 FERC COMMISSIONER MCNAMEE: No, the nuclear 19 facilities.
20 MR. KAPADIA: The nuclear should be over 97 percent 21 I think.
22 FERC COMMISSIONER MCNAMEE: Okay.
23 MR. KAPADIA: I guess I want to defer to the NRC
58 1 folks.
2 FERC COMMISSIONER MCNAMEE: Okay. All right.
3 Thank you.
4 MR. KAPADIA: Thank you.
5 FERC COMMISSIONER MCNAMEE: That's all I 6 wanted to ask.
7 NRC CHAIRMAN SVINICKI: Well, thank you again for 8 those presentations.
9 Next, we will hear a series of three presentations from 10 the NRC staff. We will begin with Mr. Eric Benner, who is the Acting 11 Deputy Director for Reactor Safety Programs and Mission Support in the 12 Office of Nuclear Reactor Regulation.
13 Following Eric, we will hear from Ms. Meena Khanna, 14 Acting Deputy Division Director of the Division of Materials and License 15 Renewal, again in the Office of Nuclear Reactor Regulation.
16 And after that, we will hear from Ms. Anna Bradford, 17 who is the Deputy Director, the Division of Licensing, Siting, and 18 Environmental Analysis in the Office of New Reactors.
19 Eric, would you please lead us off?
20 MR. BENNER: Thank you, Commissioner.
21 So, good morning, Chairmen and Commissioners. I'm 22 not sure of the exact way to reference that.
23 (Laughter.)
59 1 It's the NRC staff's pleasure to be before you today to 2 talk about our activities. Chairman Svinicki outlined our names.
3 I'll give a brief history of the interactions and the 4 formalization of those interactions between NRC, NERC, and FERC.
5 Meena will discuss the status of the operating fleet, including license 6 renewal and subsequent license renewal, as well as decommissioning 7 activities. And Anna will discuss our activities for new and advanced 8 reactor licensing.
9 Next slide, please.
10 So, we've talked a little bit, the other presenters, about 11 recent significant events. And I'll note that the formalization of the 12 arrangements between the NRC, FERC, and NERC, the genesis of those 13 was a previous significant event, the 2003 Northeast blackout. And as a 14 result of that, we realized with our missions that there was need for some 15 better understanding of roles and responsibilities.
16 So, that led to a Memorandum of Agreement with 17 NERC and a Memorandum of Understanding -- excuse me -- a 18 Memorandum of Agreement with FERC and a Memorandum of 19 Understanding with NERC. And both of those were put in place in 2004.
20 They've both been renewed twice, most recently in 2015, and the NRC 21 staff feels that those agreements have been very helpful to align on roles 22 and responsibilities as well as create mechanisms for sharing of 23 information that I think both Agencies have found useful.
60 1 More recently in 2015 -- excuse me -- 2018, the NRC 2 and NERC, or FERC entered into an MOU on the topic of critical energy 3 and electric infrastructure information, or CEII, as it's referred to on this 4 slide. That, again, gives us an additional framework for protection of 5 information that falls under that banner. And I'm happy to report that the 6 NRC does now have procedures in place to fulfill our obligations under 7 that MOU.
8 With that, I will turn it over to Meena Khanna.
9 MS. KHANNA: Okay. Thank you, Eric.
10 Good morning, Chairmen and Commissioners. We 11 appreciate the opportunity to meet with you this morning.
12 My presentation will focus on: one, an overall of the 13 current fleet of operating reactors; two, a snapshot and update of where 14 we are with regard to subsequent license renewal, and three, the status 15 of decommissioning nuclear reactors.
16 The combined output of all U.S. operating reactors in 17 2018 was over 92,000 megawatts of electricity. The map on this slide 18 displays the locations of the nuclear power plants by color, which 19 represents the four NRC Regions. The Regional Offices are located 20 outside of Philadelphia, Pennsylvania; in Atlanta, Georgia; near Chicago, 21 Illinois, and lastly, near Dallas, Texas.
22 Since the 1970s, the NRC has approved a number of 23 power uprates at these existing facilities ranging from 1 to 2 percent up to
61 1 extended power uprates on the order of 7.5 to 20 percent. These power 2 uprates have added approximately 7900 megawatts electric of additional 3 capacity to the U.S. domestic fleet of reactors. The Agency also expects 4 to receive applications in the next three years for additional power 5 uprates, yielding an additional 60 megawatts of electricity. Beyond that, 6 we do not anticipate many additional power uprate requests.
7 Licensee decisions to continue to operate or 8 decommission and to pursue license renewal or subsequent license 9 renewal are driven heavily by economics, particularly with the competition 10 from other low-cost sources of electricity generation.
11 Next slide, please.
12 The NRC has issued renewed licenses for all but eight 13 reactors of the operating fleet. Of the eight, the NRC has received letters 14 of intent indicating that licensees will submit applications for license 15 renewal for three units, and those include Clinton and Comanche Peak 16 Units 1 and 2. Watts Bar Units 1 and 2 have not indicated an intent for 17 license renewal. Diablo Canyon Units 1 and 2 will not pursue license 18 renewal since the units will be shutting down at the end of their current 19 operating license in 2024 and 2025, respectively.
20 On July 26th of this year, First Energy Nuclear 21 Operating Company indicated that they have reversed their plans to shut 22 down the Perry Nuclear Power Plant as a result of the Ohio Clean Air Act.
23 To date, FENOC has not formally notified the NRC of any specific plans
62 1 regarding license renewal. Currently, there are no applications for initial 2 license renewal under NRC staff review.
3 The graph on this slide provides information on how 4 renewed licenses have or will affect the contribution of nuclear power 5 plants to the nation's energy portfolio in the coming decades. Also, the 6 graph reflects the planned shutdowns between 2019 and 2025.
7 The red line on the graph reflects the generating 8 capacity if power was only generated during the initial 40-year licenses.
9 Next, the blue line that shifts to the right shows the generating capacity 10 with both approved and potential license renewals for which we have 11 received letters of intent for three units, as I indicated earlier. Far to the 12 right, the orange line shows the potential generating capacity if all plants 13 that renew their original license also receive a subsequent license 14 renewal approval, which leads to our next topic of discussion.
15 Next slide, please.
16 Subsequent license renewal is a term that we use to 17 describe plants seeking to operate beyond 60 years. As some plants 18 have passed 40 years of operations, industry interest has been 19 expressed for subsequent license renewal to allow for plant operation to 20 80 years. The Commission has stated that the license renewal rule has 21 provided an effective basis for ensuring safe operation during the license 22 renewal period and will continue to be an effective basis for subsequent 23 license renewal.
63 1 The staff issued subsequent license renewal guidance 2 in July of 2017 in anticipation of these applications. The NRC received 3 its first subsequent license renewal application in January 2018, and the 4 staff is currently reviewing three subsequent license renewal applications.
5 Those are for Turkey Point Units 3 and 4, Peach Bottom Units 2 and 3, 6 and Surry Units 1 and 2. The staff's goal is to complete the review of the 7 subsequent license renewal applications in 18 months.
8 We expect an application in 2020 for North Anna Units 9 1 and 2. Also, an industry survey conducted by Nuclear Energy Institute 10 has identified additional interest for subsequent license renewal 11 applications beyond 2021.
12 Last Thursday, Duke Energy issued a press release 13 indicating that it will seek subsequent license renewal for the 11 reactors 14 that they operate. Duke expects to submit the subsequent license 15 renewal application for the Oconee Nuclear Station in 2021, followed by 16 its other nuclear stations. The NRC has budgeted for the review of two 17 subsequent license renewal applications in fiscal year 2021.
18 It is the industry's responsibility to develop the technical 19 basis demonstrating safety for long-term operations. The top four 20 technical issues that are being addressed in the subsequent license 21 renewal application reviews are: neutron embrittlement of the reactor 22 pressure vessel; stress corrosion and other types of degradation of 23 reactor pressure vessel internals; concrete and containment degradation,
64 1 and electrical cable qualification and condition monitoring.
2 Next slide, please.
3 The economic and other factors that I just discussed 4 also impact utilities' decision-making on whether to decommission 5 operating reactors. The map shows you what you certainly already 6 know, the North American Electric Grid interconnections and the eight 7 regional reliability entities which NERC oversees. I included this in my 8 presentation to help convey the impact of power reactors coming offline 9 due to decommissioning.
10 The stars on the map show where we either have or 11 anticipate nuclear power plant closures through 2025. In recent years, 12 nine units at eight sites, which includes the recent Three Mile Island, 13 represent a capacity decrease of approximately 7,000 megawatts electric 14 have begun the decommissioning process. There is an additional eight 15 units which could be impacted by premature closures due to 16 decommissioning by 2025, and that could further decrease the electricity 17 capacity by about 7800 megawatts electric.
18 Perry and Davis-Besse had announced plans to 19 decommission. However, as I alluded to earlier, in July of 2019, FENOC 20 reversed its plans to shut down Perry and Davis-Besse as a result of the 21 Ohio Clean Air Act. This is similar to the situations for Clinton, Quad 22 Cities Units 1 and 2, and the Fitzpatrick sites.
23 Next slide, please.
65 1 The NRC continues its mission to ensure public health 2 and safety prior to and during the entire decommissioning process. The 3 NRC has inspection guidance for oversight of power reactors transitioning 4 to the decommissioning phase as well as following the permanent 5 cessation of operations. The inspections verify that: one, the licensee's 6 processes and procedures and programs for decommissioning are 7 adequate; two, the necessary programs continue from the period of 8 operation into decommissioning, and three, the safety culture established 9 during reactor operations is maintained.
10 Once a plant permanently shuts down, the fuel is 11 moved to a spent fuel pool where it is cooled for about five years, and 12 then, transferred into dry-cask storage. Many of the NRC's regulatory 13 requirements are not needed for assuring public health and safety for a 14 defueled reactor. Therefore, licensees must submit license amendments 15 or exemption requests to appropriately reduce the regulatory 16 requirements they transition into decommissioning.
17 We are currently applying lessons learned from the 18 previous licensing reviews into our current reviews and incorporating 19 those into our ongoing decommissioning rulemaking.
20 That concludes my remarks, and I will now turn the 21 presentation over to Anna Bradford.
22 MS. BRADFORD: Thank you, Meena.
23 Next slide, please.
66 1 Good morning, Chairmen and Commissioners. I'd like 2 to take a few minutes today to update you on the progress being made in 3 our new Light water Reactor and Advanced Reactor Programs.
4 As we mentioned last year during this meeting, we're in 5 the process of reviewing a design certification application for the NuScale 6 Small Modular Reactor. This past July, we completed Phases 2 and 3, 7 which means that we have developed Draft Safety Evaluations for all of 8 the review areas and discussed those evaluations with our independent 9 advisory committee. In some cases, there are open items that remain to 10 be resolved, and we continue to address those. We are currently on 11 schedule to complete the entire safety review by September 2020.
12 On August 14th of this year, we completed the 13 mandatory hearing for the Early Site Permit for a Small Modular Reactor 14 at the Tennessee Valley Authority site. And Early Site Permit determines 15 whether a specific site may be suitable for a nuclear reactor and allows 16 an applicant to bank that site for future use. TVA has not yet decided 17 which SMR technology they would use in a possible future combined 18 license application.
19 Additionally, the Utah Associated Municipal Power 20 Systems, or UAMPS, recently announced that they have reached the 21 megawatts threshold that they had set for themselves in order to begin to 22 pursue a combined license for a NuScale SMR at a site in Idaho. We 23 look forward to working with them and determining a schedule for moving
67 1 forward.
2 Next slide, please.
3 Earlier this year, we received a letter from General 4 Electric-Hitachi stating that they would like to begin pre-application 5 interactions on their Small Modular Reactor design, which they call the 6 BWRX-300. As the name implies, this will be a Small Modular Reactor 7 with an output of 300 megawatts electric.
8 Also, we received an application from a company called 9 Nuclear Development asking that we transfer the construction permit for 10 Bellefonte to them, so that they can complete construction of two 11 partially-constructed units and eventually apply for an operating license.
12 In April of 2019, after reviewing their application, we requested that they 13 provide additional information in the areas of quality assurance and 14 technical qualifications. As of August 28th, we have received the 15 additional information that we requested from the applicant, and we are 16 reviewing it at this time.
17 Slide 11, please.
18 In addition to those licensing activities, we are 19 overseeing the construction and startup preparations for Vogtle Units 3 20 and 4 in Georgia. Southern Nuclear Company currently plans to load 21 fuel in November of 2020 and 2021, with commercial operations 22 beginning approximately six months later. This is an area of high focus 23 for the NRC and we are ensuring we have the resources to meet or
68 1 exceed the planned schedules.
2 Next slide, please.
3 For this meeting, I wanted to find a metric that helps to 4 communicate the progress being made at the two units. It's hard to 5 numerically capture progress because so many different fronts are being 6 worked on at once. But one way to look at it is with respect to closing 7 out the inspections, tests, analyses, and acceptance criteria, or ITAAC, 8 that must be completed by the licensee and verified by the NRC before 9 the plant can load fuel.
10 We review the ITAAC to ensure that the plant has been 11 constructed in accordance with the design, the regulations, and the 12 Atomic Energy Act. As you can imagine, because most of the ITAAC 13 needs to be completed and checked near the end of construction, we are 14 expecting and prepared for a bow wave of these. However, we have 15 already closed out about 20 percent of the approximately 450 ITAAC per 16 unit and have also approved Southern's plans for closing out another 64 17 percent. These percentages are shown in the pie chart on this slide.
18 We're confident we have the resources and skills needed to complete 19 these as the project moves forward.
20 Next slide, please.
21 There continues to be a significant stakeholder interest 22 in the development and licensing of Advanced, also known as Non-Light 23 water, Reactors. Advanced Reactors thermal powers can range from
69 1 less than a megawatt to thousands of megawatts and can have a variety 2 of cooling materials, fuel types, and safety systems. The variety of 3 possible designs, which I will show on the next slide, contributes to the 4 need to develop technology-inclusive approaches instead of prescriptive 5 requirements for each design.
6 The NRC expects Advanced Reactors to have 7 enhanced safety margins and safety features as described in the NRC's 8 Advanced Reactor Policy Statement. These margins and safety features 9 should provide for greater operational flexibility than current reactors and 10 allow for more efficient licensing review.
11 We made significant progress over the past year in 12 continuing to implement our action plans, and we continue to prioritize the 13 resolution of key policy issues. And its efforts, we work closely with our 14 counterparts at the U.S. Department of Energy and have engaged 15 extensively with external stakeholders and international counterparts.
16 For example, we continue to chair the Working Group on the Safety of 17 Advanced Reactors through the Nuclear Energy Agency in Paris and the 18 IAEA SMR Regulators' Forum in Vienna, where we share information on 19 Advanced Reactor Safety and regulatory issues with international 20 regulators. Additionally, we just signed a Memorandum of Cooperation 21 with the Canadian Nuclear Safety Commission to enhance cooperation 22 on Advanced Reactor licensing activities.
23 To address specific policy issues over the past year, the
70 1 NRC staff has issued papers to our Commission regarding functional 2 containment performance criteria for Non-Light water Reactors, options 3 and recommendations for physical security for Advanced Reactors, and a 4 proposed rule for emergency preparedness for Small Modular Reactors 5 and other new technologies. All of these papers have the potential to 6 affect where Advanced Reactors could be located in the future. For 7 example, the proposed rule on emergency preparedness could lead to 8 changes in the Emergency Planning Zone sizes for new reactor designs.
9 Over the past several years, the NRC has been 10 engaged with the industry-led Licensing Modernization Project, or LMP, 11 with the goal of establishing technology-inclusive, risk-informed, and 12 performance-based regulatory guidance for licensing Advanced Reactors.
13 Industry's LMP document, also called NEI-18-04, outlines a systematic 14 approach for use by reactor developers regarding topics that are 15 fundamental to the safe design of Advanced Reactors. On May 13th, 16 2019, the NRC staff issued a Draft Regulatory Guide for public comment 17 proposing to endorse the NEI-18-04 methodology to inform the contents 18 of applications.
19 Lastly, the Nuclear Energy Innovation and 20 Modernization Act, or NEIMA, was signed on January 14th, 2019, and it 21 has several provisions related to Advanced Reactors. Consistent with 22 Section 103 of NEIMA, the NRC plans to build off of the guidance that I 23 just mentioned to complete a rulemaking to establish a
71 1 technology-inclusive regulatory framework by December 31st, 2027.
2 Next slide, please.
3 The NRC continues to interact with a broad range of 4 Advanced Reactor developers as we prepare for potential applications in 5 the next several years. This slide illustrates the wide range of Advanced 6 Reactor designs under development. It is a large and diverse landscape, 7 and this slide is not all-inclusive in that it only shows the developers that 8 are members of the industry's Advanced Reactor Technology Working 9 Groups.
10 Five designers responded to our Request for 11 Information of potential applicants to inform our budgeting process, and 12 those particular developers are shown in the shaded boxes on this 13 graphic. Our most significant pre-application interactions have been with 14 Oklo and Kairos Power, where we have been reviewing several of their 15 pre-application reports.
16 We have noticed a recent increase in possible interest 17 in microreactors from end-users and designers. The NRC has not 18 defined microreactors, but the Department of Energy uses this term to 19 describe a reactor that is capable of producing 1 to 20 megawatts of 20 thermal energy and that is factory-built, transportable, and self-regulating.
21 For example, the reactor design would utilize passive safety systems 22 and would not require a large number of specialized operators. The 23 safety, security, and environmental reviews of microreactors might
72 1 warrant even more flexible approaches as they tend to comprise simpler 2 designs with emphasis on inherent and passive features.
3 Organizationally, we continue to use a core-team 4 approach for the Oklo and Kairos pre-application reviews, which provides 5 stability and consistency to the designer while ensuring efficient use of 6 available NRC resources. This approach has been working successfully, 7 and we plan to continue to use this approach to support other Advanced 8 Reactor developers. We have made substantial progress in preparing 9 for the submittal of an application for an Advanced Non-Light water 10 Reactor.
11 This concludes this panel's presentations, and we are 12 prepared to answer any questions you may have. Thank you.
13 NRC CHAIRMAN SVINICKI: Thank you very much, 14 Anna, Meena, and Eric.
15 And for these topics, we will turn first to our FERC 16 colleagues, and I will turn to Chairman Chatterjee.
17 FERC CHAIRMAN CHATTERJEE: Thank you all for 18 very informative presentations. Nuclear is such an important resource 19 for the grid.
20 Just a couple of questions. In the past few years, we 21 have heard that the NRC and the nuclear industry were considering 22 options on possibly providing some of the nuclear reactors with 23 load-following capability or ramping capability. Is this still under
73 1 consideration?
2 MR. BENNER: I know that certain utilities are looking 3 into that. We've been supporting those licensees with questions they 4 may have. There certainly is nothing in our regulations that prohibits 5 plants from doing that.
6 FERC CHAIRMAN CHATTERJEE: Thank you for that.
7 Obviously, from the presentation, you guys seem to 8 have a sense of what units may seek a license renewal, but is there a 9 point at which the NRC expects those predictions to firm up, so we can 10 just have a better sense in predicting what the nuclear generation 11 capacity changes might be over the next decade?
12 MS. KHANNA: Thank you, Chairman Chatterjee, for 13 that question. So, we've been trying really hard to maintain the latest 14 information as far as expected subsequent license renewals as well as 15 initial license renewals that we still have to complete. So, the best that 16 we can do is we continue to have dialogs with industry. We do get some 17 informal information from them, but until they actually publicly announce 18 it, then we really can't, yes, publicly announce that to others. But we 19 continue to ask them to share that knowledge with us because we want to 20 make sure that we are prepared as well. And then, we also want to 21 make sure that we have the information to ensure that we have an 22 appropriate budget for that year to do those reviews.
23 FERC CHAIRMAN CHATTERJEE: Makes sense.
74 1 Thank you.
2 Finally, Anna, for the Advanced Reactors, what might 3 some of the drivers or considerations for selecting one design over 4 another be? Are there costs or performance considerations that would 5 help to benefit grid operators?
6 MS. BRADFORD: In terms of selecting a design, I 7 assume you mean by industry?
8 FERC CHAIRMAN CHATTERJEE: Uh-hum.
9 MS. BRADFORD: Okay. Not the NRC?
10 FERC CHAIRMAN CHATTERJEE: Yes.
11 MS. BRADFORD: All right. So, the industry, I think 12 they would take into account all of those things. Where do they want to 13 place the reactor? How much capacity do they need? Because they 14 range from very small to very large. Do they want to put it in a location of 15 a previous coal plant, which I know some industry members are thinking 16 about. So, there is a wide range of things that they need to consider, 17 which I think leads to that wide range of possible designs that you saw in 18 that slide.
19 FERC CHAIRMAN CHATTERJEE: That's very helpful.
20 Thank you all again.
21 NRC CHAIRMAN SVINICKI: Thank you.
22 Commissioner Glick?
23 FERC COMMISSIONER GLICK: Thanks.
75 1 I just wanted to follow up a little bit on Chairman 2 Chatterjee's second question, which was with regard to the expectation 3 about requests from industry in terms of license extensions, and so on.
4 Obviously, we have a proliferation or an increase in zero-marginal-cost 5 technologies, and that certainly impacts. Especially in competitive 6 markets, that has a big impact. And you mentioned that there is a 7 significant number of retirements, although we're certainly seeing 8 announcements. You mentioned Duke and others and the issue in Ohio.
9 I'm curious if you do any economic analysis, though, of 10 where you think nuclear is headed from an economic perspective; how 11 competitive that technology will be in the future compared to other 12 developing technologies and existing technologies.
13 MS. KHANNA: So, I'm not aware of us looking at the 14 economics of the various industries and everything. Obviously, there is 15 competition out there, right, with the renewables and everything. So, I 16 can tell you that what we're trying to do is make sure that we're regulating 17 at the appropriate level. We're looking back at our processes. We're 18 making sure that we're also implementing risk-informed decision making 19 where we can, and we're doing everything that we can to make sure that 20 we are regulating in an efficient and effective manner while still ensuring 21 safety. So, I'll leave this for --
22 MR. BENNER: Yes, and to build onto that, because 23 we don't know. We have done what we've called the Futures
76 1 Assessment, which has tried to look at potential landscapes, both to 2 prepare the NRC for whatever may come, but part of that activity is to try 3 to develop better signposts, so we can be nimble to respond to where the 4 industry as a whole is going. But we would not personally do an 5 economic analysis of the viability of any individual plant.
6 FERC COMMISSIONER GLICK: In general, do you 7 see that some of the newer technologies that Anna was just mentioning 8 about Advanced Reactors, and so on, is that something that would 9 potentially be more economic than some of these bigger, 1,000-megawatt 10 facilities?
11 MS. BRADFORD: So, again, we wouldn't have done 12 an economic analysis ourselves, but there are a lot out there that the 13 industry has done. And that, obviously, is a very important point to them.
14 Some of them are trying to get below a certain dollar amount per 15 megawatt, you know, so that it is cost-effective. And so, it just depends 16 on where they're going to put it, what their customer base is, what the 17 design is, all of that. It's a lot of factors to consider.
18 FERC COMMISSIONER GLICK: Thank you very 19 much.
20 NRC CHAIRMAN SVINICKI: Thank you.
21 FERC COMMISSIONER MCNAMEE: For the various 22 technologies that are being proposed, are most of them U.S. technologies 23 or are they coming from foreign developers?
77 1 MS. BRADFORD: It ranges across the board. There 2 are some that are U.S.-based, others that are in Canada, others that are 3 in other countries that I know of as part of the SMR Regulators' Forum.
4 The ones that we've been talking to the most I believe are mostly 5 American-based.
6 FERC COMMISSIONER MCNAMEE: That's it. Thank 7 you.
8 NRC CHAIRMAN SVINICKI: Thank you.
9 Anna, I'll just ask a quick question. Maybe you could 10 elaborate a little bit on your slide that was the landscape of Advanced 11 Reactors in terms of the engagement of the companies on that slide.
12 You did mention which we have had the most maybe substantive or 13 frequent engagement with. But how much does it vary? Are there 14 companies on there that we've had essentially little-to-no engagement 15 with? I just thought it would be helpful to characterize a little more 16 specifically, because they're not all at the same level maybe in advancing 17 their designs or engaging the NRC.
18 MS. BRADFORD: That's absolutely true. So, some of 19 them we might have had one meeting. Others we might have just met at 20 an Advanced Reactor conference and they said, "Hey, we want to come 21 in and talk to you. Here's our design." So, these are the ones we are 22 aware of. And then, as you said, there are some that we've been dealing 23 with quite a lot, Oklo and Kairos. So, it's a broad spectrum there for
78 1 sure.
2 NRC CHAIRMAN SVINICKI: Thank you very much.
3 Other questions? Commissioner Baran?
4 NRC COMMISSIONER BARAN: Just a quick clarifying 5 point in response to Chairman Chatterjee's question about when you 6 would have more certainty about plants seeking subsequent license 7 renewal to go to 80 years. What's not clear from this is oftentimes 8 people are submitting those applications for the next 20 years way in 9 advance of their existing license expiring. And so, with the exception of 10 the few plants that you mentioned that have announced plans to shut 11 down in the next few years, are there any, like if you're looking at the next 12 decade, are there any plants now that have their license renewed that 13 would expire in that timeframe, or is it all further down the horizon?
14 MR. BENNER: It's all further down the horizon.
15 NRC COMMISSIONER BARAN: Okay. Thanks.
16 NRC CHAIRMAN SVINICKI: Thank you.
17 Any other questions? Commissioner Caputo?
18 NRC COMMISSIONER CAPUTO: I guess one 19 question I would have just in terms of plants that are potentially closing 20 prematurely, some of those decisions seem to hinge on auctions that take 21 place in some of the regional operating systems. Do we track that at all?
22 Or do we maintain some sort of an awareness of that? Or do we strictly 23 just wait for licensees to come in?
79 1 MR. BENNER: We maintain awareness. I mean, 2 obviously, in our interactions with individual licensees, they will transmit 3 information as to say, hey, here's the next time we're coming up for 4 auction. And we don't have the specific values and everything, but they 5 give us a heads-up as to that will be a decision point for them.
6 NRC COMMISSIONER CAPUTO: So, in some cases, 7 if they clear a particular auction, do we get a sense that that gives them 8 sort of a three-year window or a two-year window, or something, where 9 they're confident they'll continue before they hit that next decision point?
10 MR. BENNER: I think it depends on the individual 11 market and the arrangement and the bid they put in. I'm not sure if 12 there's unilateral durations of how those markets work. But, usually, 13 they'll tell us. They say, "Yeah, we're likely good for this duration."
14 NRC COMMISSIONER CAPUTO: And so, some of 15 that might also depend on contracts, long-term contracts?
16 MR. BENNER: Uh-hum.
17 NRC COMMISSIONER CAPUTO: And we don't 18 necessarily get a sense of that at all because that's business proprietary.
19 NRC COMMISSIONER CAPUTO: Okay. Thank you.
20 NRC COMMISSIONER WRIGHT: I have one. Eric, 21 when a plant closes, I'm sure there's some kind of risk assessment done 22 and I'd like to just kind of have you tell me what kind of interactions do we 23 have with FERC and NERC when a plant announces, because that
80 1 capacity coming offline has got to affect the grid somehow. And is there 2 some kind of a planning that takes place with that?
3 MR. BENNER: Not so much on that regard from the 4 standpoint of -- fortunately, there's been, for most of these plants, there's 5 been lead time. So, I think what factors into those individual markets is 6 there's enough time to figure out what's going to happen in that individual 7 market. So, we haven't had explicit communications with FERC as to 8 those things. We think that the other communications around the plant 9 shutting down take care of that issue.
10 NRC COMMISSIONER WRIGHT: Fine.
11 NRC CHAIRMAN SVINICKI: Well, thank you again to 12 all the presenters at the table.
13 And as the final element in our public session, we will 14 hear presentations on cybersecurity activities from the FERC and NRC 15 staff. So, we'll just pause for a moment while we reset the table.
16 Thank you again to all of our initial presenters.
17 I guess we couldn't squeeze two more people in on 18 your side.
19 (Laughter.)
20 So, we're going to reset here.
21 But thank you all.
22 (Whereupon, the above-entitled matter went off the 23 record at 10:47 a.m. and resumed at 10:48 a.m.)
81 1 NRC CHAIRMAN SVINICKI: Okay, as our next 2 presenters are taking their seats, again we will hear two presentations 3 now on cybersecurity activities. First, we will hear from the FERC.
4 Patricia Eke is an energy industry analyst in the FERC's Office of Electric 5 Reliability.
6 Following that, we will hear from Ms. Shana Helton who 7 is the Director of the Division of Physical and Cybersecurity policy in 8 NRC's Office of Nuclear Security and Incident Response. Please 9 proceed.
10 MS. EKE: Testing, all right, great. Well, good 11 morning. My name is Patricia Eke and I work for the Office of Electric 12 Reliability, and I will be presenting on Orders number 850, Order 848, the 13 CIP-012 NOPR, and the Audits Lessons Learned Report. Next slide.
14 Next slide, please?
15 On October 18, 2018, Order 850 for Supply Chain Risk 16 Management Standard was approved. The Commission approved three 17 Reliability Standards collectively known as the Supply Chain Standards to 18 mitigate cybersecurity risks associated with the supply chain for the bulk 19 electric system cyber systems. The Supply Chain Standards become 20 effective July 1, 2020. Next slide, please.
21 The Supply Chain Standards Requirements include 22 requiring entities to develop, implement, and view a supply chain 23 cybersecurity risk management plan.
82 1 It also requires entities to be aware of all active vendor 2 remote access sessions taking place on the entity's system, and it also 3 requires entities to verify software integrity and authenticity to ensure that 4 software being installed was not modified without awareness of the 5 software supplier and is not counterfeit. Next slide, please.
6 FERC directed NERC to study certain categories of 7 assets not currently subject to the Supply Chain Standards. On May 28, 8 2019, NERC filed Cybersecurity Supply Chain Risks: Staff Report and 9 Recommended Actions.
10 Further study is to determine whether new information 11 supports modifying the standards to include low-impact BES cyber 12 systems with external routable connectivity. The formal data request to 13 address this issue was submitted August 19, 2019. Next slide, please.
14 Regarding Order number 848, this was issued by FERC 15 July 19, 2018. This order directed NERC to develop and submit 16 modifications to the NERC Reliability Standards to augment the 17 mandatory reporting of cybersecurity incidents, including incidents that 18 might facilitate subsequent efforts to harm the reliable operation of the 19 bulk electric system. Next slide, please.
20 NERC filed proposed Reliability Standard CIP-008-6, 21 which is the Incident Reporting and Response Planning Standard, and 22 this filing was done March 3, 2019. It was approved by FERC on July 23 20, 2019, and the standard becomes effective January 1, 2021. Next
83 1 slide, please.
2 Consistent with the Commission's directive, the 3 approved standard also requires certain minimum information be included 4 in the incident reports such as suspicious activity. It also includes 5 deadlines for submitting the incident reports and requires the incident 6 reports to be sent to DHS-NCCIC, or its successor, in addition to E-ISAC.
7 8 NCCIC means National Cybersecurity Communications 9 and Integration Center, and E-ISAC is Electricity Information Sharing and 10 Analysis Center. Next slide, please.
11 Now I'm going to discuss the CIP-012 NOPR, which is 12 on communications between control centers. This NOPR was issued by 13 the Commission April 18, 2019. It proposes to approve Reliability 14 Standard CIP-012, which was submitted by NERC in response to a 15 Commission directive in Order 822.
16 The NOPR proposes to direct NERC to modify the 17 reliability standard to require protections regarding the availability of 18 communication links and data communicated between bulk electric 19 system control centers. It also has to clarify the types of data that must 20 be protected. The comments were due July 24, 2019. Next slide, 21 please.
22 In 2018, Staff issued a CIP Audits Lessons Learned 23 Report. This was on March 29, 2019. The 2018 CIP Audits Lessons
84 1 Report was released, recommendations from lessons learned during 2 Commission-led CIP audits, and the report was based on audits that were 3 conducted in fiscal year 2018.
4 OER, which is the Office of Electric Reliability, led the 5 CIP Reliability Standards Audits. The Office of Enforcement assisted in 6 conducting the audits as well, and the Office of Energy Infrastructure 7 Security assisted with analyzing the data that went into the report. Next 8 slide.
9 There was also a similar report that was released in 10 2017 that covered audits from fiscal year 2016 to 2017. The 2018 report 11 had 13 recommendations and I just have a few included on the slide just 12 to give you an idea of what the recommendations look like.
13 For example, there's a recommendation to consider 14 implementing encryption for interactive remote access that is sufficiently 15 strong, and there's also a link provided on the slide where you can access 16 the report because it is public.
17 And with that, that concludes my presentation. Thank 18 you.
19 NRC CHAIRMAN SVINICKI: Thank you. Shana, 20 please proceed.
21 MS. HELTON: Good morning. I'm pleased to have 22 the opportunity to brief both Commissions regarding the NRC's power 23 reactor cybersecurity program. Next slide, please.
85 1 Today's regulatory framework, our regulations, 2 guidance, and oversight, along with industry's implementation of their 3 NRC-approved cybersecurity plans, gives the NRC reasonable assurance 4 that digital computer and communication systems and networks 5 associated with safety, security, and emergency preparedness functions 6 are adequately protected against cyber attacks.
7 Today, I will update you on the NRC's ongoing 8 cybersecurity inspection program, insights from the full implementation 9 inspections we've completed so far, and the NRC's plans going forward.
10 Slide three, please.
11 At the last joint commission meeting between NRC and 12 FERC in 2018, we briefed you on the full implementation of the operating 13 reactor licensees' cybersecurity programs, which was accomplished by 14 December 31, 2017.
15 Now we are in full implementation, which includes the 16 implementation of technical controls for all of the critical digital assets 17 identified by licensees in their cybersecurity plan.
18 Critical digital assets are those assets that if they fail, 19 could result in an adverse impact to safety, security, and emergency 20 preparedness functions, including support systems.
21 Per the NRC's regulations, licensees shall apply and 22 maintain defense-in-depth protective strategies, as well as mitigate the 23 adverse effects of cyber attacks on critical digital assets.
86 1 Full implementation also includes provisions for incident 2 response training and drills, protections against supply chain threats such 3 as validating vendors, configuration management, and audits.
4 As of this past August, NRC staff has completed 35 full 5 implementation inspections. Each inspection is two weeks long and our 6 inspection teams are comprised of two regional inspectors and two 7 technical support contractors.
8 Occasionally, staff from the NRC headquarters location 9 will support and/or observe the inspections.
10 Our staff has found that in most instances, licensees 11 understand what it takes to fully implement the NRC's cyber requirements 12 and have adequately implemented their cybersecurity programs.
13 Inspections have identified findings of very low safety significance.
14 Additionally, the industry has implemented an effective 15 operating experience program, learning from the completed inspections 16 and implementing corrective actions to ensure that their programs comply 17 with regulatory requirements. Slide four, please.
18 I'd like to highlight a few focus areas we have observed 19 from the inspections that we have completed to date. The NRC is 20 working with industry in each of these focus areas to develop and 21 improve existing guidance.
22 The first focus area listed on the slide is the portable 23 media and mobile device program. An effective implementation of a
87 1 transfer kiosk to mitigate the portable media and mobile device cyber 2 attack factor is vital to the licensee's defense strategy.
3 The transfer kiosks are integral in ensuring that the use 4 of portable media and mobile devices to transfer files such as software 5 and virus signature updates from the lesser protected networks to the 6 more highly protected networks and assets does not allow a cyber attack 7 to bypass security controls.
8 The second focus area I'd like to highlight is the quality 9 of the critical digital asset and system assessments. Our inspectors 10 have observed that the documentation of how the licensees assess their 11 critical digital assets could be improved.
12 The quality and fidelity of the licensees' assessments 13 not only impacts the NRC staff's ability to understand the licensee's 14 cybersecurity implementation, but it also has the potential to impact the 15 licensee's configuration management process in the future. Industry has 16 acknowledged this challenge and is working to improve their assessment 17 processes.
18 The third focus area I'd like to highlight is related to the 19 licensees' vulnerability assessment program. This program identifies 20 emergent vulnerabilities as identified by the Department of Homeland 21 Security and other sources and evaluates them for potential updates to 22 critical digital assets.
23 The large number of critical digital assets has
88 1 challenged the licensees' ability to ensure that appropriate updates such 2 as software patches are incorporated.
3 While the NRC believes it is important for licensees to 4 improve their programs in this arena, we also believe that plants are 5 adequately protected as there is substantial defense-in-depth in 6 licensees' cybersecurity programs.
7 Licensees are making progress in addressing this focus 8 area with the help of guidance recently developed by industry and NRC 9 staff.
10 The last focus area I'll discuss on this slide relates to 11 the ongoing monitoring and assessment program. Licensees and their 12 cybersecurity plans committed to numerous ongoing monitoring and 13 assessment requirements.
14 Inspection showed that either licensees could not meet 15 these commitments in the required time or the commitments were already 16 encompassed in other programs implemented by the licensee.
17 As a result, licensees implemented alternative 18 approaches to address monitoring and assessment program 19 requirements. The NRC performs an in-depth review of these alternative 20 approaches during each inspection to ensure compliance with the 21 regulations. Slide five, please.
22 We conducted a cybersecurity assessment earlier this 23 year, beginning in January and finishing in June. Our assessment team
89 1 was constructed to be independent and consisted of staff from the 2 Cybersecurity Branch in the Office of Nuclear Security Incident Response 3 and staff from the Office of Nuclear Reactor Regulation, as well as two 4 independent cybersecurity specialists from Idaho National Lab.
5 During our assessment activities, staff engaged with 6 stakeholders, including FERC staff. The assessment team's final report 7 summarized the feedback we received and was delivered to me this past 8 July. I tasked the staff to develop an action plan to prioritize short and 9 long-term improvements to the power reactors' cyber program.
10 In the near term, staff's efforts will focus on developing 11 a further risk-informed approach to scoping CDAs related to emergency 12 preparedness, as well as those related to balance of plant, with the focus 13 of aligning with the North American Electric Reliability Corporation critical 14 infrastructure protection standards.
15 Long-term efforts will focus on making our oversight 16 program more performance based as we look to define our inspection 17 footprint in 2021 and beyond.
18 As we proceed with carrying out the tasks identified in 19 the action plan, we will be sure to continue to coordinate with FERC, 20 NERC, and other federal partners and external stakeholders. Next slide, 21 please.
22 As shown on this slide, the technology used by the 23 operating reactor fleet is largely analog except in the instances where
90 1 licensees have implemented digital upgrades. However, new and 2 advanced reactors will incorporate as part of their design more modern 3 technology where systems are more complex, largely integrated, and 4 digital assets are more sophisticated.
5 The cybersecurity rule in Title 10 of the Code of Federal 6 Regulations 73.54 applies to all reactor applicants, including applicants 7 for new reactors, small modular reactors, and other advanced reactor 8 designs that Anna discussed in her presentation.
9 The licensees and applicants are required to submit a 10 cybersecurity plan in conjunction with their license application, and the 11 staff will review those plans relative to the licensee's technology at the 12 time of submittal.
13 With respect to reactors under construction, the NRC is 14 currently working with the AP1000 licensee, Southern Nuclear Company, 15 for Vogtle Units 3 and 4 to better understand key design elements of the 16 plant and the licensee's schedule to implement the cybersecurity 17 requirements.
18 In accordance with the NRC's regulations, the licensee 19 plans to implement its cybersecurity program in a phased approach, 20 ensuring appropriate cyber controls are in place prior to fuel receipt on 21 site, fuel load, and then systems entering service. This concludes my 22 presentation.
23 NRC CHAIRMAN SVINICKI: Well, my thanks to you
91 1 both for very informative presentations. We will begin questions this time 2 again with FERC, I think, just to even it out. Chairman Chatterjee?
3 FERC CHAIRMAN CHATTERJEE: I appreciate that.
4 Thank you, and thank you both for those excellent presentations. Supply 5 chain security is something that's been a focus for us over the last several 6 years, and I'm very proud of the work we've done to move the ball forward 7 in this area, but obviously this is an issue that cuts across critical 8 infrastructure areas.
9 So I'm curious whether you two could talk about the 10 similarities and differences between the NRC's and NERC's supply chain 11 standards? I think it would just be interesting to better understand the 12 different approaches that we've taken on this common issue.
13 MS. EKE: Should I go first?
14 MS. HELTON: Yeah.
15 MS. EKE: All right, I'll start. So the CIP reliability 16 standards that cover supply chain risk management are really embodied 17 in three standards. There's CIP-013-1, which requires the entity to 18 develop, implement, and review a plan that addresses risk for supply 19 chain risk management.
20 There's also another standard which is CIP-005-6 which 21 addresses remote access for vendors. So it requires the entity to have 22 methods in detecting when there is remote access by a vendor, and also 23 having a method to be able to disable that remote access when needed.
92 1 Last, but not the least, we have CIP-010-3 which 2 focuses on requiring the entity to address risks regarding the software 3 integrity and authenticity of supply chain.
4 And so from what I understand, one of the differences 5 between the NERC CIP supply chain standards and NRC's, which I 6 believe is the NEI 08-09, which is the systems and services acquisition 7 family, is that it applies to critical digital assets, acquisition of critical 8 digital assets, services related to critical digital assets, as well as 9 components of critical digital assets, following a licensee's cybersecurity 10 plan to the full implementation date.
11 In the NERC CIP standards, we don't have that sort of 12 overarching cybersecurity plan, and I will say that's probably the most 13 fundamental difference in how both of the frameworks are structured.
14 MS. HELTON: I think Patricia had a very good answer.
15 I just would only add that in addition to the guidance that we've 16 considered acceptable for use in the NEI 08-09 document, which does 17 address supply chain, our reactor licensees are also subject to the 18 requirements in 10 CFR Part 50, Appendix B for quality assurance and 19 quality controls.
20 So while that's not a direct requirement that says the 21 words necessarily "supply chain," it does impact their oversight of 22 vendors and we hold them accountable for that.
23 FERC CHAIRMAN CHATTERJEE: Thank you both for
93 1 that. Another thing that we've done that I'm proud of is our cybersecurity 2 reporting standard that was approved several months ago.
3 Similarly, I would just appreciate if NRC could elaborate 4 a little bit on your cybersecurity incident reporting standards or regulations 5 so that we can just understand how you guys approach this issue.
6 MS. HELTON: Sure, we published our event reporting 7 rule, 10 CFR -- I'm sorry. I'm just blanking on the -- It's 73.77, I believe, 8 is the citation, back in 2015.
9 So we have a variety of reporting requirements 10 contained within that rule. Anything that is having an impact directly on 11 the safety and security of the plant, we'll hear about it within an hour.
12 We've got four-hour reporting requirements and others contained within 13 that rule.
14 I'm not sure which differences you were particularly 15 wondering about, so I --
16 FERC CHAIRMAN CHATTERJEE: I think that --
17 MS. HELTON: If that covers your --
18 FERC CHAIRMAN CHATTERJEE: -- covers it pretty 19 well. Thank you.
20 MS. HELTON: Okay.
21 FERC CHAIRMAN CHATTERJEE: Thank you both, 22 and thank you, Chairman Svinicki.
23 NRC CHAIRMAN SVINICKI: Thank you.
94 1 Commissioner Glick?
2 FERC COMMISSIONER GLICK: Thanks. I just 3 wanted to maybe start off, Shana, with slide three of your presentation. I 4 had a couple of questions with regard to that.
5 First of all, you mentioned that you all are 63 percent 6 complete with your inspections and you'll be 100 percent, I guess, by the 7 end of next year.
8 How quickly do you start all -- after you finish the 100 9 percent, do you start all over again? How long does it take to go through 10 the cycle?
11 MS. HELTON: Thank you for that question. So that 12 relates directly to the work that we're going to be undertaking as part of 13 our action plan to look at the overall cyber program, which, you know, 14 we're taking a look at our regulations, our guidance, but also our 15 oversight.
16 One thing that I should mention is that we've had some 17 very intensive -- our team's on site for two weeks at a time for these cyber 18 inspections. We do want to look at if there's a way to streamline and 19 make those more efficient and effective going forward.
20 We feel that was an appropriate level of inspection for 21 looking at the initial full implementation by licensees, but going forward, 22 we have an interest in further risk informing.
23 Our inspections are already somewhat risk informed,
95 1 and we think that there's places where we could do more to further risk 2 inform, as well as perhaps look at performance-based indicators and see 3 if we could use those to influence our inspection program, so that's work 4 that we're going to be undertaking in the very near future.
5 FERC COMMISSIONER GLICK: Okay, great, so you 6 also mentioned in your inspections so far, you've just found findings of 7 what you call very low safety significance. I was wondering if you can 8 give maybe an example without revealing too much of what that might 9 be?
10 MS. HELTON: Sure, in some cases, we've inspected 11 where licensees may have controls in place. They might be a little bit 12 different than what was described in their cybersecurity plan. Licensees 13 are allowed to take alternative measures, but it's mainly a documentation 14 issue.
15 So in those cases, they've been of low safety 16 significance, very low safety significance because they do have 17 appropriate alternative measures in place and there is substantial 18 defense-in-depth, but they need to reflect that in their cybersecurity plans.
19 FERC COMMISSIONER GLICK: Okay, finally, on 20 supply chain, and supply chain is clearly one of the biggest threats 21 throughout, not only in the electric sector, but throughout the economy 22 wide, but I'm just wondering, you mentioned --
23 It was kind of interesting when you said this. You
96 1 mentioned obviously that a lot of the nuclear facilities are still analog in a 2 lot of ways and maybe older equipment.
3 Some have digitized, you mentioned, and I think on the 4 electric grid, we're facing more digitization probably than you all are on 5 the nuclear side, but I'm just wondering if that makes the threat of supply 6 chain cybersecurity incidents less likely because you all are, because 7 nuclear plants, at least the existing ones, are more analog?
8 MS. HELTON: We have a trend of plants going more 9 towards digital, and just broadly speaking, I think there can be challenges 10 with trying to replace an analog design just from the standpoint that that 11 component may or may not be produced any longer.
12 And manufacturers are moving more and more towards 13 using digital where they can, so we rely on licensees' configuration 14 management processes, and as they acquire new systems, they do need 15 to look at the cybersecurity involved with that.
16 FERC COMMISSIONER GLICK: And how do they 17 do -- do you have specific requirements about how they address that?
18 MS. HELTON: Yes.
19 FERC COMMISSIONER GLICK: Okay.
20 MS. HELTON: And that's contained in their 21 cybersecurity plans that they've committed to, as well as a license 22 condition.
23 FERC COMMISSIONER GLICK: Okay, thank you.
97 1 NRC CHAIRMAN SVINICKI: Maybe I'll just kick off on 2 the NRC side. Commissioner Glick made a reference to, you know, the 3 whole economy and how interconnected a lot of systems are.
4 From my vantage point, I think there's been an 5 emphasis over the last 10 years on really improving interagency 6 coordination across it. I think Shana had mentioned federal partners.
7 There's a lot of partnership going on.
8 Would either of you like to offer your observation or 9 assessment of how effective, and the improvements that we're trying to 10 make in terms of, you know, parts of the U.S. government talking to each 11 other?
12 Because we're talking electrical systems today, but of 13 course telecommunications is the backbone for a lot of what's going on, 14 and then there's financial systems interconnected with 15 telecommunications.
16 So how would you characterize the overall level of 17 interagency coordination? And in addition, this gives you a chance to 18 say nice things about each other.
19 MS. HELTON: So, yeah, we have our legally binding 20 memorandum of agreement, MOUs, of course, but on top of that, I know 21 at the staff level, we have very frequent communications between FERC 22 and the NRC.
23 In the area of cyber, we've done an extensive -- what I
98 1 consider. I've been in many places in the agency and I think that in the 2 area of cyber, that's one of the places where we are very, very well 3 connected.
4 That said, the interagency is a changing landscape and 5 there's always new groups and subgroups that are popping up, so I think 6 that we do a good job between our two agencies of keeping each other 7 well informed of each other's activities.
8 And especially moving forward, as we update our 9 program for the cybersecurity reactor oversight program, and our 10 regulations and our guidance, we recognize that there is a strong need to 11 interact with FERC, especially in the area of balance of plant, so we've 12 already been engaging in discussions.
13 NRC CHAIRMAN SVINICKI: Thank you. Would you 14 like to offer an observation as well?
15 MS. EKE: Yes, I'd like to echo Shana's comments, 16 especially on the staff level. I think we pretty much have been 17 exchanging information pretty well.
18 In fact, I did see actually someone that I knew here on 19 supply chain who is like a supply chain guy here, and, you know, we 20 would reach out and ask questions and exchange information, so it's 21 been a pretty health process, and an enjoyable one and, yeah.
22 NRC CHAIRMAN SVINICKI: Okay, thank you both.
23 Other questions? Commissioner Baran?
99 1 NRC COMMISSIONER BARAN: I just had a couple of 2 questions on Order 850 on supply chain cyber. Who are the affected 3 entities required to comply with Order 850?
4 MS. EKE: So with Order 850, the entities that comply 5 are the entities that are applicable to the CIP reliability standards.
6 NRC COMMISSIONER BARAN: Okay.
7 MS. EKE: And so the way the applicability portion of 8 the CIP standards are determined is we have a standard called CIP-002, 9 which categorizes different BES cyber systems and facilities based on 10 impact ratings, and so that kind of feeds into the applicability section per 11 standard.
12 NRC COMMISSIONER BARAN: And so it's, generally 13 speaking, generating units and transmission entities?
14 MS. EKE: So it's mostly high and medium impact BES 15 cyber systems.
16 NRC COMMISSIONER BARAN: Okay, and I see that 17 that standard becomes effective next year. At this point, does the FERC 18 staff have a sense of how these entities will go about verifying the 19 integrity and authenticity of software and hardware?
20 MS. EKE: So really the software integrity piece and 21 authenticity piece of it really is just making sure that you have methods to 22 address risks of an attacker exploiting the patching process, so that they 23 don't deliver, you know, a software that has some kind of compromise in
100 1 it, and so there are different methods that they can use to do that.
2 NRC COMMISSIONER BARAN: Thank you.
3 NRC CHAIRMAN SVINICKI: Other questions?
4 Commissioner Caputo?
5 NRC COMMISSIONER CAPUTO: I think I'm going to 6 get just -- I'd like to ask for a little clarification --
7 NRC CHAIRMAN SVINICKI: Okay.
8 NRC COMMISSIONER CAPUTO: -- on Commissioner 9 Baran's questions about the affected entities under your regulations. Is it 10 limited to the grade? You said high and medium impact entities, so is it 11 grid operators plus generating facilities, or is it generating facilities down 12 to a certain threshold in size?
13 MS. EKE: Okay, so an example of a high, medium 14 BES impacts, the high, medium BES impact system would be, for 15 example, a control center or backup control center that has functions of a 16 reliability coordinator, or another way to look at it is facility elements that 17 will create 500 KV and above. That's a high impact BES cyber system.
18 And then for the medium, it would be anywhere from, a 19 transmission facility from 200 KV to 499 KV, and then low, which is not 20 affected in this particular reliability standard, is 100 KV to 200 KV.
21 NRC COMMISSIONER CAPUTO: Okay, so a 22 generating station doesn't fall under these requirements at all?
23 MS. EKE: I'd have to look at the standard to clarify
101 1 that. Sorry I don't know off the top of my head.
2 NRC COMMISSIONER CAPUTO: Okay.
3 MS. EKE: Yeah.
4 NRC COMMISSIONER CAPUTO: Thank you.
5 NRC CHAIRMAN SVINICKI: Commissioner Wright?
6 Okay, well, with that, again I want to thank these presenters, but also all 7 of the presenters we've heard from this morning, and with this, we will 8 now adjourn the public portion of this meeting. Thank you.
9 (Whereupon, the above-entitled matter went off the 10 record at 11:16 a.m.)