TRANSCRIPT OF ALLOWABLE EX PARTE BRIEFING

PUBLIC SERVICE COMMISSION OF SOUTH CAROLINA 101 EXECUTIVE CENTER DRIVE POST OFFICE BOX 11649 COLUMBIA, SC 29210 COLUMBIA, SC 29211

WWW.PSC.SC.GOV

BEFORE THE PUBLIC SERVICE COMMISSION OF SOUTH CAROLINA

COLUMBIA, SOUTH CAROLINA

HEARING # 14-11408 FEBRUARY 27, 2014 10:00 A.M.

ALLOWABLE EX PARTE BRIEFING - DOCKET NO. 2014-3-E: REQUESTED BY SOUTH CAROLINA ELECTRIC & GAS COMPANY Regarding Events of January 7, 2014, Impacting Company’s Electric System

TRANSCRIPT OF ALLOWABLE EX PARTE BRIEFING

COMMISSIONERS PRESENT: G. O’Neal HAMILTON, CHAIRMAN, Nikiya M. ‘Nikki’ HALL, VICE CHAIRMAN; and COMMISSIONERS John E. ‘Butch’ HOWARD, Elizabeth B. ‘Lib’ FLEMING, Swain E. WHITFIELD, Comer H. 'Randy' RANDALL, and Brent L. MCGEE ADVISOR TO COMMISSION: Joseph Melchers, Esq. STAFF: F. David Butler, Senior Counsel; James Spearman, Ph.D., Executive Assistant to Commissioners; B. Randall Dong, Esq., Josh Minges, Esq., and David Stark, Esq., Legal Staff; William O. Richardson, Tom Ellison, and Lynn Ballentine, Advisory Staff; Jo Elizabeth M. Wheat, CVR-CM/M-GNSC, Court Reporter; and Hope Adams and Allison Minges, Hearing Room Assistants APPEARANCES:

K. CHAD BURGESS, ESQUIRE, along with STEPHEN A. BYRNE [COO and President, Generation & Transmission], JOSEPH K. TODD [General Manager, Fossil & Hydro Operations], PANDELIS N. XANTHAKOS [Vice President, Electric Transmission] and W. KELLER KISSAM [President, Retail Operations] representing SOUTH CAROLINA ELECTRIC & GAS COMPANY JEFFREY M. NELSON, ESQUIRE, representing the SOUTH CAROLINA OFFICE OF REGULATORY STAFF

http://www.psc.sc.gov/

Ex Parte SCE&G / Events of 1-7-2014 Impacting 2 Briefing Company’s Electric System

2/27/14

PUBLIC SERVICE COMMISSION OF SOUTH CAROLINA

I N D E X

PAGE OPENING MATTERS........................................... 3-5 PRESENTATION: Stephen A. Byrne .................................. 5 Joseph K. Todd ................................... 18

Question(s) by Vice Chairman Hall ........... 27 Pandelis N. Xanthakos ............................ 28 W. Keller Kissam ................................. 50 Question(s)/Comment by Commissioner Randall................ 64 Question(s)/Comment by Commissioner Whitfield.............. 69 Question(s)/Comment by Commissioner Howard................. 72 Question(s)/Comment by Commissioner Fleming................ 83 Question(s)/Comment by Commissioner McGee.................. 93 Question(s)/Comment by Chairman Hamilton................... 97 Question(s)/Comment by Vice Chairman Hall.................. 98 REPORTER’S CERTIFICATE.................................... 101 Please note the following inclusions/attachments to the record:

• PowerPoint presentation (PDF) For identification of additional referenced materials and links for same, please see:

• ORS correspondence filed as part of the ex parte briefing process


2/27/14


P R O C E E D I N G S 1

CHAIRMAN HAMILTON: Please be seated. We'll 2

call the ex parte to order and ask Attorney 3

Melchers if he would please read the docket. 4

MR. MELCHERS: Thank you, Mr. Chairman and 5

Commissioners. We are here pursuant to an Amended 6

Notice of Request for Allowable Ex Parte Briefing, 7

scheduled for February 27th at 10 a.m., here in the 8

Commission hearing room. 9

The party requesting the briefing is South 10

Carolina Electric & Gas Company, and the subject 11

matter to be discussed at the briefing: The events 12

of January 7, 2014, impacting SCE&G's electric 13

system. 14

Mr. Chairman, that is all. 15

CHAIRMAN HAMILTON: Thank you, very much. 16

Mr. Burgess. 17

MR. BURGESS: Good morning, Mr. Chairman, 18

Madam Vice Chairman, and members of the Commission. 19

My name is Chad Burgess, and I am corporate counsel 20

for SCE&G. 21

[Reference: PowerPoint Slide 1] 22

It is our pleasure to appear before you today 23

and we appreciate this opportunity to allow the 24

company to come visit with you, talk with you about 25


2/27/14


the events that transpired just shortly before 1

January 7th and then on January 7th, and how those 2

events impacted SCE&G's electric system. 3

We've got a slide deck with about 60 slides in 4

it. I know that sounds like a lot, but they move 5

at a pretty good clip. 6

We've got four presenters to share with you 7

today: Stephen A. Byrne, who is SCE&G's president 8

of Generation and Transmission, and also our chief 9

operating officer. He's going to set the table for 10

you, give you a high-level summary of the things 11

that we were experiencing that day, and also give 12

you some data points to put some items into context 13

for you. 14

Followed by him, we have Joseph Todd, who is 15

our general manager of Fossil and Hydro Generation. 16

He's in charge of the generating plants. He’s 17

going to talk to you about the generating plants 18

and some of the issues that they were experiencing 19

from a mechanical standpoint that day. 20

And then, followed by him, will be our vice 21

president of Electric Transmission, and that is Mr. 22

Lee Xanthakos. 23

Following Mr. Xanthakos is going to be Keller 24

Kissam, and he's going to talk with you about the 25


2/27/14


distribution side of our system, and he's going to 1

discuss with you the instructions that Mr. 2

Xanthakos's team was giving him as far as what to 3

do in the field, as far as voltage reduction and 4

the load shedding that occurred. 5

So, without further ado, I'll ask these 6

gentlemen to come up here and sit at the table. 7

Mr. Chairman, if you want to interrupt us at 8

any time to ask questions, please feel free to do 9

so, or if you want to hold it till the end, that's 10

totally up to y'all in how you want to handle that. 11

But we're here, like I said earlier, at your 12

pleasure, and we want to give you all the 13

information that you need, to do your job. Thank 14

you, very much. 15

CHAIRMAN HAMILTON: Thank you, sir. Welcome, 16

gentlemen. 17

MR. STEPHEN BYRNE [SCE&G]: Thank you, Mr. 18

Chairman and members of the Commission. It's a 19

pleasure to be in front of you today in this ex 20

parte format. Much better than being on the 21

witness stand. 22

[Laughter] 23

This event, we recognize, happened about seven 24

weeks ago, so to some of us it seems like just 25


2/27/14


yesterday; but then there've been so many things 1

that have transpired in the last few weeks that it 2

does seem like it was an eternity. So we see both 3

ends of the spectrum. 4

We have a team here today that represents the 5

areas that dealt, for the most part, with the 6

rolling load-shedding incident, or controlled load-7

shedding incident. And I'm going to try to step 8

through -- first of all, I'm going to set up a 9

quick reminder -- maybe I'm not. 10


-- of what happened on January 7th. I 12

probably don't have to remind you that it was cold 13

that day? 14

[Laughter] 15

The "polar vortex" has entered into our 16

vocabulary, and I'm not sure whether it was record-17

setting cold, but it certainly was cold. 18

You can see from the pictures here that the 19

cold temperatures certainly spread well to the 20

south. Joe will talk to you in a few minutes about 21

the kind of temperatures we saw at some of our 22

generating facilities. I will tell you that at our 23

V.C. Summer Plant in Fairfield County, we did see 24

single-digit temperatures recorded there. 25


2/27/14


The complicating factor for this one was that 1

it wasn't just cold; it was very windy, 2

particularly in the overnight hours, the dark hours 3

between 6 and 7. So we saw fairly sustained 30-4

mile-an-hour winds, so that added a complicating 5

factor to the already cold temperatures. 6


And this is a map of SCE&G's generation and 8

our service territories. If you look at the dark 9

blue, that's our electric service territory. 10

Combine that with the light blue and that's 11

electric and gas, so the light blue portion is gas. 12

The green portion, of course, is not our service 13

territory. 14

And our plants are listed here, and you can 15

see we've got a fairly diverse fleet of coal, gas, 16

hydro, nuclear. And the gas comes in two different 17

forms. We've got simple-cycle, which means we just 18

burn natural gas or oil in a simple turbine, and 19

the heat is exhausted to the environment. In a 20

combined-cycle plant -- or sometimes referred to as 21

CC gas, or combined-cycle natural gas -- you run 22

the natural gas or oil through the turbine, which 23

generates electricity, and then you capture the 24

reject heat in what's called a heat-recovery steam 25


2/27/14


generator. It then makes steam, and you send that 1

steam to a steam turbine and make electricity. So 2

there's two cycles; that's why they call it a 3

combined-cycle. And we have five plants that are 4

combined-cycle natural-gas plants. So those plants 5

tend to be able to ramp up fairly quickly and start 6

up fairly quickly. Some of our other units are 7

much slower to start off. You take a traditional 8

coal plant, you're not going to start it up in a 9

few hours if it's shut down. If it's cold, it'll 10

take one to two days for that plant to start up. 11

So this is our generating fleet, and we did 12

have some issues with some of these plants on that 13

cold January morning. 14


All right. I wanted to give you a sense for 16

what our system looks like on an hourly basis for 17

loads, and what I'm going to do is step through one 18

week, and that happens to be the week in question. 19

So January 7th was a Tuesday, and I'll step you 20

through from Sunday to the following Saturday. 21

So the left-hand column is megawatts, so 22

that's the power rating we're putting out. Across 23

the bottom, or the X axis, that's the hours. So 24

it's "hour ending..." and the first one would be 25


2/27/14


1 o'clock in the morning. 1

So this[see legend, slide 4] is what it looked like on 2

the 5th, which would've been Sunday. And you can 3

see it's a fairly flat load curve, and our peak was 4

just under 3000 megawatts, so relatively low. 5

This[see legend] was the next day, so this would've 6

been Monday. And you can see that the peak was 7

just under 4000 megawatts, so quite a bit higher, 8

and the low that day was much lower, so you see a 9

much bigger swing in the low to high on that day. 10

Here[see legend], by contrast, is January 7th, so 11

this was the Tuesday morning. You can see in the 12

morning we have a peak that's right around 8 a.m. 13

-- or Hour Ending 8 -- so generally, people are 14

waking up; they're starting their coffeemakers, 15

making breakfast. Some commercial and industrial 16

facilities are starting up. So we tend to see load 17

peaks, particularly in the wintertime, at this 18

point in time. 19

You can also see that, in the afternoon, on 20

January 7th, we saw another peak, actually, in 21

early evening -- Hour Ending 1900. So in the 22

wintertime, we tend to be bimodal, so we get a peak 23

in the morning and we get a peak in the afternoon. 24

Summertime peaks are different; we generally get a 25


2/27/14


peak in the summertime, and that's much later in 1

the day than the Hour Ending 8 o'clock. So you can 2

see a significant increase in load in this swing. 3

Let's go to the next day[see legend]. So here is 4

Wednesday, and on this Wednesday you can see that 5

we didn't quite peak at the same level as we 6

peaked, but it was still a pretty high day. That 7

Wednesday, also, the difference between the peak 8

and the minimum was in excess of 1500 megawatts. 9

So on a system that was generating under 5000, we 10

see a swing from day to night of 1500 megawatts on 11

that Wednesday. So we have to account for those 12

things, which means we're generally ramping plants 13

back or shutting plants down. 14

Most of our plants have a minimum load, which 15

means I can only take them down so far, and below 16

that, I really need to take the plant off-line. 17

The minimum load for most of our coal facilities 18

has been around 50 percent of their normal power 19

output, so if I have a plant that was, say, 500 20

megawatts, the minimum load would generally be 21

around 250 megawatts. As we have added the 22

emissions controls to those plants, that minimum 23

load has actually increased, so now it's about 60 24

to 65 percent of full load, is our minimum load. 25


2/27/14


Otherwise, the pollution-control equipment gets 1

more unstable and the plant gets unstable. So we 2

have to account for these swings, not only seasonal 3

swings but actually daily swings, in plant loads. 4

Let's continue with the 9th[see legend], 10th [see 5

legend], and finally on Saturday[see legend] you can see 6

that that's a fairly low-load day. The difference 7

between our peak on the 7th and our minimum on the 8

11th was about 2269 megawatts, so a fairly 9

significant swing during that same week. 10


Another complicating factor during this week, 12

and certainly on the 7th, was what we call 13

operational flow orders that we get from the gas 14

suppliers. Generally, in South Carolina, we get 15

gas from one of two pipelines: SONAT, which is 16

here in purple, or Southern Natural; and then 17

Transco, which is in the lime green color. That 18

actually -- the Transco line actually crosses the 19

state in the upstate region. SONAT does actually 20

cross into South Carolina, but just briefly. So we 21

generally get our gas from one of those two 22

pipelines. 23

And on the day in question -- and actually for 24

a good portion of that week -- there were 25


2/27/14


operational flow orders in effect where the 1

suppliers said, "You can't have any more gas than 2

you have firm contracts for." So, particularly in 3

the Northeast where it gets very cold, when they 4

have a need for gas there, if we're siphoning off 5

all the gas in the South, then it robs them, so you 6

have to lock into firm transportation. 7

Generally, we would only need firm 8

transportation a couple of days a year, and so we 9

don't lock into more than we need; otherwise, it 10

adds to the cost. So we do have firm 11

transportation on these pipelines to supply our 12

Jasper facility and to supply our Urquhart 13

facility. Those are both our combined-cycle 14

facilities. We do not do firm gas for our peaking 15

units. 16

So when the operational flow orders came in, 17

all of our peaking units were curtailed on natural 18

gas, which means we have to then run them on oil. 19

So we do keep a stock of oil at each of facilities, 20

so that we can run the plants on oil. And, indeed, 21

if we were to run at full output on all of our 22

combined-cycle plants, we wouldn't have enough gas 23

to run those plants. 24

Now, people oftentimes hear about how 25


2/27/14


inexpensive natural gas is, in the $3-$4 a 1

dekatherm range? Well, on these days, it wasn't in 2

the $3-$4 a dekatherm range. So you can see on the 3

chart that's up here, this is just a listing. On 4

Transco Zone 5, which we would be in, the price on 5

January 6th -- which is the day before -- was just 6

under $11 a dekatherm. January 7th, the day in 7

question, it was over $70 a dekatherm. It didn't 8

return to more normal levels until January 9th. So, 9

even had gas been available to us, it would have 10

been very expensive. But bottom line is, because 11

of those operational flow orders, we couldn't get 12

the gas to our system. 13


There's a big-picture timeline, and we're 15

going to cover the timelines in a little bit more 16

detail in two of the presentations you'll see after 17

mine. But we were going through our cold-weather 18

preparations on January 6th. We also were under 19

those operational flow orders -- in fact, had come 20

in a little bit earlier than that. I think they 21

started as early as the 3rd of January for 22

operational flow orders. 23

We did advise our interruptible industrial 24

customers that there was going to be a possibility 25


2/27/14


of interruptions, based on what we saw as the load 1

coming in and based on these cold temperatures. So 2

our interruptible customers -- our industrial 3

interruptibles -- were notified that this might be 4

a possibility. 5

On January 6th -- so this is the evening 6

before -- we had problems with one of our combined-7

cycle units. Now, at Urquhart, we have three older 8

coal facilities -- those would be Units 1, 2, and 3 9

-- and we converted two of those units to combined-10

cycle gas turbines, so we added the gas turbine, 11

which, in this case, would be Unit six. And then 12

its heat-recovery steam generator then sent steam 13

to the old steam turbine, which was Unit 2. So 14

when we talk about our combined-cycles at Urquhart, 15

Units 6 and 2 is the combined-cycle plant. We had 16

some problems with Unit 2, but we were able to get 17

Unit 6 on-line. Those were not weather-related 18

problems. They weren't caused by the cold weather. 19

Then on January 7th, in the wee hours of the 20

morning, a little after 2 a.m., we did lose 21

Urquhart Units 5 and 1 -- it automatically shut 22

down; in our parlance, we would say the plant 23

tripped, or tripped off-line -- which is about 242 24

megawatts. 25


2/27/14


And then on January 7th, the day in question, 1

at about 6:21 a.m. -- which is about the worst time 2

possible for a plant to come off-line, because load 3

is building in at this point in time -- we lost our 4

Williams unit, which is a coal facility near 5

Charleston, and that is 610 megawatts. 6

So we had a lot of our load come off all in a 7

relatively short period of time. And, as Joe Todd 8

will talk to you about in a few minutes, both the 9

Urquhart 5 and 1, and the Williams units were 10

weather-related shutdowns. 11

Other utilities around us were experiencing 12

some similar problems to what we were experiencing, 13

and so some of the reserves that we were calling on 14

from other utilities were recalled. And so, the 15

actions we took were actually to preserve the grid 16

-- that's one of our primary focuses, is: preserve 17

the grid. And so, we did request standby 18

generators to start. We do have some turbines on 19

our system from some of our customers that they can 20

start and actually start supplying the grid, so we 21

called on those, and they responded. We called on 22

reserve-sharing from our neighboring utilities, and 23

they responded and gave us some of that power early 24

on. We did shut down the interruptible industrial 25


2/27/14


customers, so that preserved load, and that's just 1

under 200 megawatts’ worth of load impact. 2

We then did voltage reduction. So you drop 3

the voltage a little bit, and it reduces the power. 4

So our load was shaved somewhat by reducing 5

voltage. 6

And then, as a last resort, we went into a 7

controlled load-shedding scenario, where we brought 8

off some of the load in some blocks. And Mr. 9

Kissam will talk a little bit more about what that 10

controlled load shedding looks like, in a few 11

minutes. 12


So why did we have the issue? 14

At the close of business, so let's say in the 15

afternoon on Monday, January 6th, our projections 16

for the following day were as follows: 17

We looked like a load peak at about four 18

thousand eight hundred fifty megawatts, so 4850 19

megawatts. We had reserves of about 560 megawatts, 20

so above that 4850 we had that 560 megawatts of 21

reserves. 22

The actual loads came in higher than that, 23

because the temperatures we saw were actually 24

colder, compounded by the wind effects. And then 25


2/27/14


when we lost the Urquhart and Williams units, that 1

was just under 1100 megawatts of our load that came 2

off-line, so you can see that's significantly in 3

excess of the reserves that we were carrying on 4

that day. 5

And when the utilities around us, that were 6

supplying us with this emergency power experienced 7

problems of their own and had to recall that 8

emergency power, that's when we had to get into the 9

load-shedding scenario. 10


So, in summary, we know that any interruption 12

of power to our customers is a huge inconvenience 13

and we certainly regret that. We did set a total 14

energy record on January 7th, so we sold 101,118 15

megawatt-hours of electricity. So we're generally 16

a summertime peaking utility, but we set this all-17

time peak in the wintertime. 18

The actions that we took were taken to 19

preserve the grid. That's one of our paramount 20

goals, is to preserve the grid. 21

We shed the load in a controlled fashion. It 22

wasn't willy-nilly. And Mr. Kissam will show you 23

exactly how that load was shed, in a few minutes. 24

Our transmission and our distribution system 25


2/27/14


did function as we would have expected, given the 1

loss of generation. So really it was the loss in 2

those generating assets, combined with the 3

utilities around us that had to recall that power, 4

that caused this problem, but the transmission and 5

the distribution system acted as they should have. 6

We can protect our plants from cold weather, 7

but it's going to come with a significant cost. 8

Some of our plants -- particularly, plants in the 9

south -- are outside. We're going to show you some 10

pictures in a few minutes of some of those outside 11

plants. Now I could completely enclose those 12

plants and protect them from cold weather, but that 13

would come with a significant cost. 14


So we're going to show you now how our 16

generation system performed and what the problems 17

were with those generation facilities. So Joe 18

Todd, who is our general manager for fossil-hydro 19

operations, will take you through that. 20

MR. JOSEPH TODD [SCE&G]: Good morning, Mr. 21

Chairman and members of the Commission. 22


I'm going to talk about fossil-hydro issues on 24

January 6th and January 7th, as Mr. Byrne 25


2/27/14


mentioned. As he already talked about and 1

everybody knows, we had a pretty significant cold 2

snap the week of January 6th. Temperatures were as 3

low as 12 degrees in Columbia and Augusta, 18 4

degrees in Charleston, with some significant wind 5

speeds in the morning. Thirty [30] miles an hour 6

is what we recorded. 7

We also had significant lost-generation issues 8

at both Williams Station and Urquhart Station, and 9

we've got more information on these issues in the 10

attached slides. And I am covering the period from 11

noon on the 6th through noon on the 7th. 12


For cold-weather preps, I want to talk a 14

little bit -- before we get into the details -- 15

about what we do. We do cold-weather preps when 16

cold weather is expected. Normally, we do that in 17

November of each year at each of the plants, before 18

winter. Also when we have extreme cold weather 19

predicted, we'll go out and do those checks again. 20

It's worth noting that we did those checks on 21

the morning of January 6th, in anticipation of the 22

cold weather coming through. We also instructed 23

our plants to avoid any maintenance or testing that 24

could impact reliability of the units. We did that 25


2/27/14


that morning. 1


Typical cold-weather checks: This is -- our 3

plants are different, but these are typical ones, 4

depending on the plant. We ensure external louvers 5

are closed. We check area heat pumps and space 6

heaters. We will check heat-tracing panels; that's 7

automatic freeze protection, and that's very 8

important. We'll talk more about that later. 9

We have portable heaters on hand, in the event 10

they're needed. That's not our primary means, but 11

we have that on standby in case we need it. We 12

bring in extra manpower to be on standby, in case 13

of problems. And we did that at Urquhart Station 14

on the night of the 6th. And we also run peaking 15

gas turbines on fuel oil, for reliability checks. 16

We did that on most of those peaking turbines that 17

morning, on January 6th. 18


Mr. Byrne also talked about gas-supply issues. 20

And just a little more detail: We were under a 21

curtailment for gas, starting on January 3rd, well 22

in advance of this event. We do have firm gas 23

pipeline capacity in place for Urquhart and Jasper, 24

but, as he said, not enough to run full load 25


2/27/14


around-the-clock. These gas supplies were being 1

balanced to have enough gas for full load during 2

peak times. We were also running some units on 3

fuel oil, as part of the balancing plan. We'll 4

talk about some of those details later. And 5

although it can be complicated, we do it all the 6

time, and we'd like to point out that gas 7

availability was not a factor in these events of 8

January 6th and January 7th. 9


And for a general timeline, again, Mr. Byrne 11

talked about that. I will get into more detail on 12

all of these. We did tie Urquhart 6 on-line around 13

12:08 p.m., on the 6th. You'll see there was a lot 14

going on at Urquhart on this day. We had Urquhart 15

3 in startup beginning at 1:15. The first glitch 16

occurred at 3:20 p.m., when we were unable to tie 17

Urquhart 2 on-line. This was not weather related. 18

Urquhart 6 tripped on a fuel-oil transfer at 19

10:30 p.m. Again, this was not weather related. 20

The first weather-related glitch occurred at 21

2:05 a.m., when Urquhart 5 and 1 tripped. And, as 22

Mr. Byrne mentioned, a "trip" to us is when a unit 23

comes off-line very quickly, due to an automatic 24

shutdown. 25


2/27/14


At 2:58 a.m., Urquhart tied on-line with gas, 1

so it came on. That's about 95 megawatts. And 2

then the big one is 6:21 a.m., Williams tripped, 3

and that was 610 megawatts right when the cold was 4

coming in on us. 5


For Urquhart 2, the -- 3:20 p.m., we were 7

trying to get it on-line with Urquhart 6. The 8

cause of this was a generator breaker malfunction. 9

This was not weather related, and we were able to 10

get this issue resolved in the next day or so, 11

and we got it on-line, I think, within a day or a 12

day and a half. Again, not weather related on 13

Urquhart 2. 14


Urquhart 6, we did have the trip on transfer 16

of fuel oil. This was part of the plan to balance 17

the gas. Our review indicated we had a leaking 18

fuel purge valve. It took them sometime that night 19

to figure that out. We did not have a spare at 20

Urquhart; we did have a spare at Jasper, so we had 21

to get that transported up to Urquhart. They got 22

it later that morning, and we were able to get 23

Urquhart 6 back on-line that afternoon. That was 24

January 7th. 25


2/27/14



The first weather-related glitch occurred at 2

2:05 a.m. This is Urquhart 5 and 1. It tripped 3

while we were burning natural gas; and the cause of 4

this trip was a frozen steam drum pressure 5

transmitter supply line. This is a very small line 6

going to the transmitter -- I'll show you a picture 7

in a minute. It really doesn't have a lot of flow 8

in it, and it's protected by heat tracing and 9

insulation, and I'll talk more about that in a 10

minute. 11

And it's worth noting that this line froze 12

despite the presence of automatic freeze protection 13

that was heating the line at the time of the trip. 14

So it was heating; it's just that the cold weather 15

and the winds overwhelmed the system. 16

Complications with additional freezing and an 17

industry issue with gas-turbine fuel control inputs 18

delayed the restart. We found out later that this 19

gas-control issue affected approximately 50 units 20

in the country on that day. 21

Urquhart 5 and 1 was returned to service on 22

January 8th, after we got through all of these 23

issues. 24



2/27/14


This is a picture of the drum pressure 1

transmitter at Urquhart. I'm not sure if the 2

pointer is working -- there it is. This is the 3

transmitter right here [indicating], the blue part. 4

We call this a Rosemount pressure transmitter. And 5

this is about 60 feet up in the air on the Savannah 6

River. So we had those cold temperatures of 12 7

degrees, but also the 30-mile-an-hour winds were 8

coming through, which pushed wind chills down close 9

to zero, or definitely in single digits. And the 10

insulation -- you can see the cloth insulation 11

below that that was on that sensing line. The 12

transmitter didn't freeze; it was somewhere in that 13

sensing line that we had the freezing issue. 14


Okay. The next one -- and again, the big one 16

-- was at 6:21 a.m., when Williams Station tripped. 17

It's a 610-megawatt winter rating. That's our 18

largest coal-fired plant. 19

The review indicated, again, we had a frozen 20

pressure switch supply line as the cause. Again, 21

the supply line is the same or similar as to what 22

we had at Urquhart; it's just that it was a 23

pressure switch on this one. And when it froze, it 24

initiated an automatic shutdown of the unit to 25


2/27/14


protect the unit. 1

We did have heat tracing on this line, this 2

automatic freeze protection. We have two heat-3

trace circuits that cover this line; one was 4

working and one was not. The circuit that was not 5

working had indication at the power source that the 6

breaker was energized and it was showing that 7

voltage was going to it; it's just that somewhere 8

along that line, there was a problem beneath the 9

insulation, and we really had no way of knowing 10

that that problem occurred until we found it later. 11

This heat-trace circuit has obviously been 12

repaired. We repaired that one pretty quickly. 13


This is a picture of the pressure-switch 15

enclosure at Williams, and you can see the pointer 16

there. The line that froze was the sensing-line 17

supply line from above. I think you can see that 18

in there. And you can see it's insulated. The 19

heat tracing was below that. It's just a 20

resistance -- kind of like a little, mini heating 21

blanket, but it's a little resistance heating 22

circuit that goes along there. And one of those 23

circuits just did not work on that day. 24

And you can see where the pressure switches 25


2/27/14


are inside this cabinet right here [indicating]. 1

That's very heavily insulated. And like Urquhart, 2

this is an exterior unit; we don't have an enclosed 3

boiler, and so this is at least eight or nine 4

stories in the air with 30-mile-an-hour winds 5

blowing through, so it was a tough morning up 6

there, from a cold standpoint. 7


In summary, as discussed, weather-related 9

issues resulted from an equipment malfunction on 10

automatic freeze-protection systems. Similar 11

issues occurred throughout the industry with 12

transmitter freezing and transmitter lines 13

freezing, and also with the gas control inputs on 14

large gas turbines. 15

We continue to work on corrective actions and 16

lessons learned as a result of this event. This is 17

exhaustive, and we're going to take our time to 18

make sure we do it right. These items will be 19

addressed; once we get our lessons learned, we're 20

definitely going to address these items to ensure 21

we learn from this event and make any necessary 22

improvements. 23

With that, I'll stop and answer any questions, 24

or if y'all want to wait till the end, we can do it 25


2/27/14


at the end. 1

CHAIRMAN HAMILTON: We'll just wait till the 2

end. 3

MR. JOSEPH TODD [SCE&G]: Okay. Next we have 4

Mr. Lee Xanthakos. 5

CHAIRMAN HAMILTON: Mr. Todd, I think we do 6

have one for you. 7

MR. JOSEPH TODD [SCE&G]: Okay. 8

VICE CHAIRMAN HALL: I'm sorry, Mr. Todd, to 9

interrupt you, but my attorney and I were -- we 10

can't figure this out. Was it the gas that was in 11

the line -- did it freeze? Or -- I'm not sure I 12

understand. 13

MR. JOSEPH TODD [SCE&G]: Great question. 14

What these are, it's a pressure transmitter. And 15

what they do is they sense the pressure; in the 16

case of Urquhart, the pressure in the steam drum, 17

and it's water that's in the line. 18

VICE CHAIRMAN HALL: Okay. 19

MR. JOSEPH TODD [SCE&G]: But we're just 20

trying to monitor the pressure in the line, so that 21

if it overpressurizes, we'll shut the unit down so 22

that we don't do permanent damage to the heat-23

recovery steam generator at Urquhart. That was the 24

situation there. So it was water in the line for 25


2/27/14


us. 1

VICE CHAIRMAN HALL: Okay. 2

MR. JOSEPH TODD [SCE&G]: And at Williams, 3

it's a very similar situation -- a little different 4

-- but it was a water-wall pressure switch that 5

froze. Again, it's monitoring the pressure in the 6

water wall, so that if they go high, we shut the 7

unit down and avoid any damage to the unit until we 8

can bring it back. 9

VICE CHAIRMAN HALL: Okay, thank you. 10

Thank you, Mr. Chairman. 11

CHAIRMAN HAMILTON: Yes, ma'am. 12

Thank you, Mr. Todd. 13

MR. LEE XANTHAKOS [SCE&G]: Good morning. 14


CHAIRMAN HAMILTON: Good morning, sir. 16

MR. LEE XANTHAKOS [SCE&G]: My name is 17

Pandelis Xanthakos, but I go by "Lee," which makes 18

it easier for most folks. 19

CHAIRMAN HAMILTON: Thank you, Lee. 20

[Laughter] 21

MR. LEE XANTHAKOS [SCE&G]: Yes, sir. 22


I'm vice president of Electric Transmission at 24

SCE&G. One of the departments that reports to me 25


2/27/14


is the Transmission Operations Center. This is 1

sort of the control center for the transmission 2

system and for generation dispatch at SCE&G. My -- 3

an analogy of that would be sort of like the 4

control center at NASA, where it's the hub of 5

activity: Directives go out, information comes in, 6

and decisions are made. 7

There's three major functions that take place 8

in the control room. These are NERC-defined 9

functions. NERC is the North American Electric 10

Reliability Corporation; they're the regulatory 11

body that sets the standards by which we operate. 12

The first desk picture here is called the 13

Reliability desk. The folks that work on that desk 14

are called reliability coordinators. Before any 15

action is taken by either of these two desks[indicating 16

Transmission, Balance/Interchange], it is studied by the 17

reliability coordinator. That includes planned 18

outages, planned dispatch of utilities; any type of 19

other planned work that we know about is studied by 20

this desk, and it doesn't take place unless they 21

determine that it will be reliable for our system. 22

These two desks here [indicating Transmission, 23

Balance/Interchange] operate in a real-time environment. 24

They implement the plans that go through 25


2/27/14


this [indicating Reliability] desk. The first one, called 1

the transmission operator, is the person that talks 2

to our field personnel by radio. So if you can 3

imagine a transmission lineman or a substation 4

electrician getting directives to open a switch in 5

the field, or close a breaker in the field, they 6

don't take that action unless they're directed to 7

do so by the individual here [indicating Reliability]. 8

There's a lot of reasons for that: safety, 9

reliability, coordination. So they're the voice on 10

the other end of the radio that the field people 11

speak to at the transmission level. 12

The third desk is called the Balance and 13

Interchange desk. It performs two functions by 14

NERC definition. One function is balancing; the 15

other function is interchange. I'll address 16

interchange briefly, but the main purpose of this 17

presentation will go back to balancing. 18

“Interchange" is when, on a coordinated basis, 19

on a planned basis, our company buys or sells 20

electricity from other utilities. So, on a regular 21

day like today, if it's cheaper for us to purchase 22

off-system than to generate, that interchange 23

transaction goes through this desk [indicating 24

Balance/Interchange]. 25


2/27/14


So the purchase of electricity would be 1

essentially the equivalent of increasing generation 2

at a power plant; or the sale of electricity, the 3

effect on our system, would be the equivalent of 4

generation being lower on our system -- okay? -- 5

because it's leaving. So they perform the Balance 6

and Interchange function. The main purpose of the 7

rest of our conversation is going to be around the 8

balancing aspect. 9


I wanted to cover a little bit of history. 11

There have been a number of uncontrolled cascading 12

blackouts in North America. These are two of the 13

more recent ones. This actual slide has been 14

abridged to just include these two. The original 15

slide has about 12 or 15 additional blackouts that 16

have happened since 1965, all over different parts 17

of our country. 18

The main thing to remember about these two 19

major outages is that they were uncontrolled and 20

they were cascading. What that means is that the 21

system controller sitting at the other two 22

desks [Indicating Transmission, Balance/Interchange] that I described 23

in the previous slide, these events happened and 24

they were surprised by it. They happened, and then 25


2/27/14


they were shocked; they lost control of their 1

system; they had to take some type of a corrective 2

action to figure out what to do after that. 3

In the Northeast blackout, this one is the one 4

that sort of initiated the mandatory reliability 5

standards. About 50 million people without 6

electricity, some of them without electricity for 7

up to a week. The Southwest blackout happened a 8

little more recently. The geographical area 9

appears somewhat large, but there were pockets of 10

power in here. 2.7 million people without 11

electricity, some of them for up to two days. 12

So the reason I bring these up is we do not 13

want this to happen in the Southeast. And more 14

importantly than that, we do not want to be the 15

cause of it, if it does happen in the Southeast. 16

And that's a major goal. And, basically, when I 17

try to describe my job to my friends and neighbors, 18

that's what I tell them. That's my main purpose. 19


This is a slide that should be somewhat 21

similar from earlier in the presentation. It's a 22

little bit modified. The plants have been taken 23

off and replaced by a very general description or 24

visual depiction of our transmission system. This 25


2/27/14


is not an engineering drawing; it's just a 1

representation. And what it does is it outlines 2

this area of our service territory, which, by NERC 3

definition, is called a balancing area. It's the 4

geographical boundaries that are encompassed within 5

meters, so it's a metered boundary. So between us 6

and the neighboring utilities that serve these 7

other areas, there are meters that separate us. 8

Now, we are responsible for this area [indicating]. 9

Others are responsible for these other areas 10

[indicating]. 11

We have, by the NERC definition, absolute 12

authority to control the generation and 13

transmission system within this area, and we are 14

responsible for it. And maintaining the balance 15

between the load that the customers demand and the 16

generation that we put on the system to meet that 17

load is our primary function. Okay? So we 18

generally do not control the load; load comes on 19

when a customer cuts on his hairdryer or stove or 20

lights or machines. We respond to that by adding 21

generation to the system. As they remove that 22

load, we respond by taking generation off the 23

system. Okay? That's what is supposed to happen. 24



2/27/14


Are there any questions before I go on? 1

[No response] 2

So I mentioned that we serve this area. There 3

are utilities around us that serve others. Here's 4

that picture. 5

This is just to give you an idea of the 6

companies, because they were also affected by this 7

polar vortex. They also assisted us when they were 8

able to, and stopped assisting us when they were no 9

longer able to do so, and that plays a major role 10

in here. But we have the two Duke companies to the 11

north of us: I call them traditional Duke and Duke 12

Progress. SEPA is a very small hydro-facility. 13

Southern Company's a very large company to our 14

west, going all the way to Alabama. And Santee 15

Cooper is the co-op in our state. 16

Duke Progress is connected to PJM. PJM is a 17

large RTO in the Northeast. By comparison, our 18

peak load, which you saw, is around 5000 megawatts; 19

PJM is around 151,000 megawatts. So, significantly 20

larger than us, but we are connected to them and 21

can get assistance, if necessary, if it's 22

available. Also of note is that Southern is around 23

40,000 and the Duke companies collectively are 24

around 30,000. 25


2/27/14



So this is a representation of the balance 2

that I've talked about. On the left here, we have 3

where customers demand electricity. So if you can 4

imagine this seesaw or teeter-totter, as customers 5

start to put load on this Demand side, it starts to 6

kind of go one way. We don't want it to go too far 7

that way, so we add System Resources on the other 8

side to balance it out. 9

As you can imagine, lights and machines are 10

coming on constantly, coming off constantly. So 11

keeping this at a perfect zero balance is 12

impossible to do, nor is it expected. The NERC has 13

allowed us an operating range of plus-or-minus 52 14

megawatts. What that means is that we can be out 15

of kilter in either direction by 52 megawatts, 16

which means we can take in up to -- well, let's say 17

-- 51 off of the grid, without any penalty, for as 18

long as we want; or we can push out up to 51 for as 19

long as we want, without penalty. There's a lot of 20

reasons you don't want to do that, but from a 21

penalty standpoint that's what we're allowed to do. 22


So to further that analogy, here is a 24

representation of a customer load. As the load 25


2/27/14


comes in, the system becomes out of balance. 1


Here's the response we have: We add 3

generators -- or could be system purchases -- to 4

the other side, and balance it out. 5

Now, important in this is the fact -- there's 6

a small square to the bottom right of the 7

presentation. Important in this is the reserves. 8

We carry extra power on the side -- it's on-line 9

and spinning, but it's not generating -- to use if 10

one of these units trips. You know, they can trip 11

suddenly -- they're machines -- and we carry 12

reserves on the side. That's called operating 13

reserves. 14

Now, the NERC requirements say that a 15

balancing area has to carry one time its largest 16

unit in reserves. On our system, our largest unit 17

is basically two-thirds of V.C. Summer, which is 18

over 600 megawatts. That would be very expensive 19

to do. Imagine a unit, just like V.C. Summer, just 20

sitting there, not making any electricity but just 21

waiting in case there's an emergency. So what the 22

NERC standards also allow is that utilities -- like 23

the ones that I showed you on the other 24

presentations that are together -- can share 25


2/27/14


reserves. So instead of us carrying 600 megawatts 1

of reserves, we carry a portion of that. They also 2

carry a portion of that and make it available to 3

us, if necessary. We do the same, in reverse. 4

They don't carry their full whatever-their-largest-5

unit-is; they carry a portion of that, but we 6

provide our reserves to them, if necessary. And 7

the thinking is that if enough groups get together, 8

you're not going to have -- usually -- a lot of 9

companies losing power plants at the same time. 10

You might have one company losing power plants, or 11

maybe two, but collectively if there's 15 companies 12

carrying reserves, the other 13 will be able to 13

help out. And that's the thinking behind that, so 14

it's economical. 15


We are part of the VACAR reserve-sharing 17

group. VACAR is an old name in our industry; it 18

stands for Virginia-Carolinas. And we carry, 19

together, 1694 megawatts of reserves. That is the 20

commitment we have made to carry. That's above the 21

NERC requirement. The NERC requirement is one time 22

the largest unit in the area, which is around 1100 23

megawatts. We've made the decision to carry one 24

and a half times that, just to be safe. So that's 25


2/27/14


what we carry, at least that. At least that, on a 1

daily basis. 2

On January 6th, the day before the polar 3

vortex, we had a conversation with VACAR -- which, 4

these conversations happen all the time; every day, 5

there's a scheduled call, sometimes more than one 6

-- and we added up all of our reserves. We were 7

carrying the 1694 plus an additional 3000 extra 8

megawatts of reserves. That's a lot of extra 9

reserves. I wish I had a better word than "a lot," 10

but that's a lot. 11

[Laughter] 12


So, this was our plan the day before, on 14

January 6th. This is around 3 o'clock, close of 15

business. Our load forecast for the next day was 16

4850. This is a representation of the units we 17

were running. We were carrying, by ourselves, 560. 18

Remember, our requirement's around 200, so we were 19

carrying over two times our requirement, and VACAR 20

had an additional extra 3000. So, not a bad day, 21

by any definition. 22


Later that day, just before midnight -- Mr. 24

Todd talked about the loss of Urquhart No. 6. That 25


2/27/14


was 160 megawatts. The load forecast -- as you get 1

closer to a certain hour, you can better predict 2

what the weather is going to be, right? I mean, 3

you know, we know tomorrow better than we know 4

seven days from now. So as we got closer to 5

January 6th, the weather forecast changed a little 6

bit. We adjusted our forecast by 50 megawatts. 7

So you take this additional forecast of 50 8

megawatts, this 160, you add it all up together; 9

SCE&G was still carrying 358 megawatts of reserves. 10

We were still expecting to get the 160 back 11

from Urquhart No. 6, so if you add those together, 12

you're in a pretty good situation. It's still not 13

a bad situation. And, again, this is almost -- not 14

quite twice, but almost twice our required reserve 15

numbers. 16


So the timeline of the 7th. And what I've 18

done here is -- there's a lot of steps. What I've 19

done is grouped them by the hour. Okay? So this 20

[indicating] is all between the second and the 21

third hour, and so forth. 22

As we start to get into that morning, 23

remember, a forecast is just a forecast. Real-time 24

rarely is exactly the same as a forecast. 25


2/27/14


Sometimes our load forecasts are a little high; 1

sometimes they're a little low. That's just part 2

of it. 3

The load, in reality, was tracking about 375 4

megawatts ahead of the forecast. So already the 5

load was coming in more heavily than we had 6

expected. The reason that's important is, we can't 7

ignore that. We've got to increase generation 8

somewhere or use generation from somewhere to 9

accommodate that 375 megawatts. 10

Now, on a typical day, on a typical night, we 11

use excess electricity to pump at Fairfield Pumped 12

Storage Station. That puts water in Fairfield 13

Pumped Storage, so that we can generate with it 14

later on in the day. On this day, because we were 15

using that extra 375 to serve load, it was making 16

it very, very difficult for us to pump water into 17

Fairfield Pumped Storage. The problem with that 18

is, if you don't get enough water into the pond, 19

you don't have enough water later on in the day to 20

generate. So we were being -- we were very well 21

aware of that and being very cautious with how we 22

were using Fairfield Pumped Storage. 23

There was no power available on the markets. 24

What that means is that the Interchange portion of 25


2/27/14


that Balance and Interchange desk called the 1

marketers and said, "We need to buy some power." 2

Marketers called back and said, "There is no one 3

selling any power, anywhere. There is no power to 4

be had. Everybody's holding onto it because of 5

this weather." 6

Ultimately, Fairfield Pumped Storage ended up 7

about one and a half foot below the level that we 8

would've liked to have seen it at, and that's 9

because we've used this power to serve the load 10

that was coming in higher than expected. 11

Between the 2 o'clock and 3 o'clock hour, we 12

lost Urquhart Unit 1 and 5. That was around 240 13

megawatts. The reserve-sharing group makes power 14

available to you, if you have used your own 15

reserves first. You can't just call on Duke's 16

reserves or Progress's reserves, and just hold mine 17

back. I've got to use mine first. So that was 18

where we first used our emergency reserves for that 19

day. 20

So even though we were already not getting as 21

much water into Fairfield as we wanted, we had to 22

crank up Fairfield now to accommodate the 200 23

megawatts, 230 megawatts, of lost generation. So 24

not only is the pond lower than what we would've 25


2/27/14


liked, but we're having to use it sooner than we 1

would've liked, as well. 2

We sent a message to the interruptible 3

customers for a 15-minute curtailment. They came 4

off-line. We think we got around 200 megawatts of 5

load reduction from those interruptible customers. 6

That's a very good number. 7

Going forward, between the 3 and 4 o'clock 8

hour: The way the reserve-sharing group works is, 9

if you have the unit trip, you don't have to call 10

on those reserves immediately at the time of the 11

trip. You've got 12 hours or until the end of the 12

day, whichever is longer, to call on those 13

reserves. And that's because they realize that 14

there's facilities like Fairfield Pumped Storage 15

that you may use them to solve your emergency but 16

it's limited in how long it can run, because it 17

eventually runs out of water, so they allow you 12 18

hours or end-of-day, whichever is longer, to back 19

off of that unit and then call on reserves -- if 20

that makes sense. 21

So between the 3 and 4 o'clock hour, even 22

though the unit tripped earlier, we went ahead and 23

called on reserves, so that we could back off of 24

Fairfield. Keep in mind, the whole time, we're 25


2/27/14


trying to preserve that water because we knew -- 1

like Mr. Byrne's slide showed -- it was going to be 2

cold, and it was going to be cold for the rest of 3

the day, not just that morning. 4


At 6 o'clock, the standby generator 6

participants cranked up, and that gave us about 35 7

megawatts of relief. And everything is going fine 8

at this point. You know, it's a normal tight day, 9

a typical tight day in the control room. 10

At 6:21, we lost Williams Station for 610 11

megawatts. That's the second largest generator on 12

our system, going into what was ultimately the 13

highest-use day on our system, so pretty much the 14

worst time for this unit to trip. 15

We called on emergency reserves from two 16

companies. So, rough numbers here, if we lost 600, 17

why did we call on 400? That's because in the 18

previous hour, remember we had called on emergency, 19

so we had already backed it down some. We crank it 20

back up again, and we call on 400 megawatts of 21

reserves. 22

We initiated voltage reduction through the 23

Distribution dispatch offices. Mr. Kissam is going 24

to talk more about that in detail, but basically 25


2/27/14


what happened is, the System controller -- who, as 1

I said, is the authority on the system, over the 2

transmission system -- called the Distribution 3

dispatch office, which is an equivalent office for 4

lower voltages, and directed them to initiate 5

voltage reduction. So what that did, they were 6

able -- well, Keller will get into that. We think 7

that that gave us around 40 to 50 megawatts of load 8

relief. 9

In that same hour, we lost a small unit at 10

Urquhart, 49 megawatts. It was able to tie back 11

on. It really didn't play a major role in this 12

load shed. 13

Toward the end of the hour, we had a 14

conference call again with our VACAR partners. 15

We'd lost some big units; we were calling on a lot 16

of power. Everyone wanted to see where we stood, 17

collectively. And basically it was determined that 18

everyone had used all of the reserves that were 19

available. So not just the 1694 that we carry 20

through commitment, but the additional 3000 extra. 21

Of course, we were carrying 560, and we had run 22

through all that. And these companies were 23

experiencing a similar type of situation, so there 24

were no more reserves for us to call on if 25


2/27/14


something tripped. 1

Between the 7 and 8 o'clock hour, we didn't 2

have anything trip. Unfortunately, other companies 3

had problems or continued to have problems, and 4

they were providing us for reserves. The way the 5

group works is, you take care of yourself first, 6

and then you help others if you're able to, and 7

they were no longer able to provide those 200 8

megawatts of reserves to us, so they called them 9

back. There were no other reserves for us to call. 10

So, remember that ACE number that I showed, 11

that we're allowed to be positive-or-negative 52? 12

I was in the control room then. Our ACE was about 13

-130 at that time when they called them back, and 14

it was getting worse, because load was continuing 15

to come in. 16

I didn't say this earlier. One of my first 17

jobs with the company was sitting those desks and 18

being System controller. And when the System 19

controller said, "We have to shed load," all I 20

could think about was, "There's nothing left to do. 21

He's right, we have to shed load." I could not 22

think of anything for us to do otherwise or 23

differently. And that stands to today, as well. 24

There's nothing else we could've done. 25


2/27/14


So we directed Distribution dispatch to shed 1

150 megawatts of load. The utilities around us, we 2

stay in contact with them constantly. The system 3

controllers know each other by first name; they 4

talk on the phone regularly. They knew we were 5

having trouble, so one of them made us aware of 100 6

megawatts that they were able to get -- and keep in 7

mind, these plants trip; sometimes you can bring 8

them on quickly, if they're a simple-cycle turbine 9

or a combined-cycle unit, and sometimes you can't. 10

And in some of these cases, they were able to get 11

some of their plants back on-line, so we were able 12

to get 100 megawatts of power from a company, and 13

we were in communication with the Distribution 14

dispatch office and directed them to hold that 150 15

megawatts of load shed to just 100 megawatts. And 16

so we sort of stabilized there for a little bit. 17


The word got out that we were in need of 19

power. Other companies stepped in and started 20

sending us what energy they were getting available 21

from their units, and we were able to get 300 22

megawatts of reserves then from two other 23

companies. And what that did is, it allowed us to 24

back down Fairfield. 25


2/27/14


Still not a good situation. We've shed load. 1

We're getting as much power as we can, and we're 2

still generating heavily at Fairfield. But as 3

power is coming in, we're backing down Fairfield. 4

So when Urquhart -- oh, excuse me. When 5

Williams tripped, I said it was a typical stressful 6

day? When we lost the reserves and had to shed 7

load, it became a bad day. And then between this 8

hour, all the companies -- both -- it was two 9

companies -- independently lost plants; they both 10

called and took all the reserves back they were 11

sending us. So between the 8 and 9 o'clock hour, 12

we lost 810 megawatts of reserves that we were 13

getting. So we were not receiving any reserves on 14

our system at that time. 15

COMMISSIONER FLEMING: So what kind of day was 16

it then? 17

MR. LEE XANTHAKOS [SCE&G]: I'm not sure I'm 18

allowed to say. 19

[Laughter] 20

It was a very bad day. 21

COMMISSIONER FLEMING: You're keeping me on 22

the edge of my seat. 23

MR. LEE XANTHAKOS [SCE&G]: So Fairfield is at 24

full load again; it's at low elevation. And we 25


2/27/14


direct Distribution dispatch to shed 200 more 1

megawatts of load. 2

Again, this is all sort of in bullets, but 3

we're talking about over a 60-minute period. So 4

later on in the hour, one of the companies was able 5

to give us 200 megawatts back. But, still, we are 6

shedding load. Keep in mind -- and that's why I 7

keep repeating about Fairfield -- we've got another 8

peak that afternoon to worry about, and so, as 9

these numbers come in, we're not reducing our load 10

shed yet; we're reducing water at Fairfield to try 11

to prevent something similar in the evening, if we 12

needed Fairfield. 13

Between the 9 and 10 o'clock hour, we were 14

able to get 500 megawatts of power in from two 15

companies. I should add that we got power from 16

companies that were not part of the VACAR sharing 17

group. They called neighboring utilities and asked 18

them if they had power to send to us, and we were 19

able to get from other companies, as well. 20

The focus as this power comes in is reducing 21

generation at Fairfield. And as we're getting it 22

in, the load starts dropping, because it's getting 23

warmer outside, and we start directing Distribution 24

dispatch to restore the load that they had shed. 25


2/27/14


That started between the 9 and 10 o'clock hour 1


Between 10 and 11, we restored the remaining 3

load shed; and between 11 and 12, we cancelled the 4

voltage reduction, and -- I think it was at exactly 5

12 o'clock -- directed the interruptible customers 6

to end their curtailment and come back on-line. So 7

for that morning, the event was over for us at 8

noontime. 9


This is my last slide. It's just a 11

representation of some of our recent winter loads. 12

You can see that some of them are in the 4860 13

range, which is not much different than the load we 14

saw on the 7th. Some are in the 3000s. So it 15

bounces around a bit, depending on the temperature. 16

We've gone back and done some analysis. Our 17

gross load, had there not been any interruptions, 18

would have been 5100 megawatts, which would have 19

been not just an all-time winter peak; it would've 20

been an all-time peak, including summers as well, 21

which stresses that it was a particularly cold day 22

and that we do have the ability to peak in the 23

wintertime. 24



2/27/14


So that's the end of my presentation. If 1

there's any questions, I can answer them now or 2

later. 3


MR. LEE XANTHAKOS [SCE&G]: Thank you. 5

MR. KELLER KISSAM [SCE&G]: Mr. Chairman, 6

Madam Vice Chair, and fellow Commissioners, we 7

appreciate the opportunity to be here today and 8

appreciate your interest in this matter. 9

Mr. Byrne, Todd, and Xanthakos have given you 10

an overview of the state of our system. I'll give 11

you an overview of how that impacted our customers 12

as we went through this process. 13

I think you can take it that the four of us 14

communicate on a daily basis to keep all this in 15

balance. That's what we do each and every day. I 16

talk to these three gentlemen probably more than I 17

do anybody within my given organization, and that 18

communication is of critical importance when you're 19

faced with a situation such as this, and trying to 20

come out of a situation such as this. 21


First thing to remember is, we were not 23

experiencing any overload situations on the 24

distribution or the transmission system. Now, when 25


2/27/14


I talk about the transmission system, I'm talking 1

about the same system he[Mr. Xanthakos] controls, but I 2

have the linemen in the field that actually work on 3

that system on a daily basis. Understand also, 4

based upon the blackouts that we had in the 5

Northeast, that he calls the shots and I do exactly 6

what he says and I don't ask any questions of him. 7

And none of my linemen go out there, either, during 8

construction, operations, and maintenance, and do 9

anything on that system until it passes by both his 10

Reliability and his Switching desk in order for 11

them to have permission. 12

And that's important to understand, because 13

everything we do in a situation such as this, and 14

everything we do during this type of event is to 15

preserve the integrity of the transmission system 16

so you do not have a cascading blackout of 17

catastrophic consequences that Mr. Xanthakos showed 18

you on that map. And that's the ultimate goal. 19

Distribution work schedule, we did modify it 20

due to the low temperatures. You don't want to go 21

out there and drop a limb in the line and have a 22

difficult time picking customers back up. You 23

don't want to be changing out a pole hot and get it 24

in the line and knock customers off. 25


2/27/14


During cold temperatures, it's extremely 1

difficult to pick customers up. Think about 2

somebody with an electric furnace. When they're 3

out for a period of time and that furnace comes 4

back on, what's going to be running? The heat 5

strips. That puts out a lot of resistance; that 6

puts out a lot of amperage, and you have to pick it 7

up section by section, instead of just being able 8

to pick it up at the substation. 9

So like Mr. Xanthakos, like Mr. Todd, we 10

prepare for the cold weather, as well, and we take 11

the necessary precautions on what we're doing from 12

a maintenance standpoint on our line. 13


In order to prepare for a situation such as 15

this, every June we look at our customers and how 16

they're served, based upon the hundreds of circuits 17

that we have on our system. So we look at those 18

circuits, because things change. Hospitals are 19

built and come on-line. You may have seen in the 20

paper recently where Palmetto Health has got one 21

that's coming on-line, and that's going to change 22

the dimensions of that circuit; it's going to add a 23

human-needs type facility to that circuit. 24

Everything we do, we try to focus on public 25


2/27/14


health and safety of our communities. And we look 1

at those on an annual basis, and then we prepare 2

for an event such as this. 3

We review, also, our coordination with system 4

control and Distribution dispatch. Mr. Xanthakos 5

talked about that. He has system control that 6

operates the transmission system. I have two 7

Distribution dispatch facilities -- one in Columbia 8

and one in Charleston, manned 24 hours a day, seven 9

days a week -- that do the same thing for 10

Distribution. But you can imagine from what you 11

have heard here this morning, there has to be a 12

high level of coordination between these two areas 13

within our company. 14


Now, let's talk about how we go about 16

prioritizing customers, because that was a lot of 17

the question that came out from this entire process 18

from the public, and some misunderstanding, and 19

then hopefully we can get some understanding. 20

The breaker that you see on this schematic 21

represents a substation. Y'all have them all in 22

your neighborhoods. On this, we have a school, a 23

subdivision, and we have a shopping center; so you 24

have some retail, you have residential, and you 25


2/27/14


have a school. Now, you look at schools and say, 1

"Well, why aren't schools exempt from a load-2

shedding scenario?" And they're not, because if you 3

exempted schools, you wouldn't be able to shed any 4

load, because there is a school in every community 5

that we serve, and they cannot be exempt. But the 6

whole purpose of load shedding is, it is a rolling 7

process where you cut the customer off, and then 8

you bring them right on. 9

The average outage for our customers during 10

this event was 39 minutes, when we cut them off and 11

bring them back on. So you roll that load, and 12

therefore you're able to achieve that reduction in 13

voltage on the system that Mr. Xanthakos is going 14

to need to protect that transmission grid. 15

So these Category 1s would be the first level 16

or category that we would enact our load reduction. 17

And understand, we do all of this automatically. I 18

told you we prepare for it in June and review the 19

system? Well, we have a computer system there with 20

dispatchers who are enacting this, and we do it all 21

remotely. We're not sending trucks out in the 22

field to have to do this. Y'all have heard me talk 23

to you before about SCADA switches that we have in 24

the field? Well, that communication allows us to 25


2/27/14


do this quickly and efficiently. 1


You'll see a difference here. This is a 3

Category 2. And the difference that you'll see in 4

this is we've added a large commercial. And if you 5

have a large business or a large commercial 6

establishment that is providing people with jobs, 7

and it needs to run to promote the economic 8

exchange going on during the course of a day, we 9

make them a Category 2. So that's the difference 10

between a Category 1 and a 2. 11

Now, a 2, that load will still be shed; it'll 12

just be done at a later time as we go through this. 13

As you can imagine, he[Mr. Xanthakos] called up and he 14

said, "I want 150 megawatts. Shed." Well, we go 15

to Category 1s. Maybe some Category 2s would get 16

into that. When he goes into a situation where, 17

ultimately, he says, "Shed 300 megawatts," well, 18

then, we're going to get into the 1s and the 2s, in 19

order to make that happen. 20

Ultimately, to protect that transmission 21

system, we go 1, 2, and 3. And if that didn't hold 22

it, then you'd go through a transmission load 23

shedding, in which Mr. Xanthakos would do it out of 24

system control with Transmission, and he wouldn't 25


2/27/14


even care about these categories, because at that 1

time all you're interested in is preserving the 2

integrity of that transmission grid. 3


This is a Level 3. As you see there, I've 5

added two things here: Coming out of that 6

substation, you have a hospital, a human-needs type 7

facility, and you have a water treatment plant, so 8

either providing sewage treatment or water 9

treatment. That's a higher priority. So what I've 10

established here for you are the three categories 11

that we go through on the load shed, starting with 12

1 and culminating with 3. 13


This graph shows you we have 675,000 customers 15

on our electric system, and basically it gives you 16

a timeframe from when this started at 7:49. 17

Actually, I will tell you, the first call I got was 18

from Mr. Xanthakos at 5:30 in the morning, from his 19

office to my office, to say, "We're going to have 20

to make some decisions today." So we knew the cold 21

weather was there. We knew we were going to have 22

to watch the system closely; we didn't know that it 23

was going to be to the level that we did. 24

So we started looking at this at about 5:30 in 25


2/27/14


the morning, but this shows you that the first load 1

shed occurred at approximately 7:49. It went 2

through about 10:50. And I'll talk to you about 3

some of the other events that occurred at this same 4

time. 5

Understand that, prior to this, we did have 6

some 20- to 30-mile-per-hour winds that night, so 7

we had some other events going on on the system 8

before we even entered in this, primarily in our 9

western area around Aiken. But this basically 10

shows you that there were approximately 50,000 11

customers that were impacted, on an average of 39 12

minutes, as a result of the activities that 13

occurred on January 7th, the morning of. 14


As Mr. Xanthakos talked, when we got the call 16

from system control to implement distribution 17

voltage reduction, that bought us probably about 50 18

to 60 megawatts of load savings. And what we do on 19

that is, this is what our dispatchers look at. 20

They see a schematic, and they send information out 21

to that transformer and it says "reduce voltage." 22

We cut voltage from 120 to 118 volts. And what 23

that does is it basically saves you load. 24



2/27/14


What happens on this is there is a device 1

called a load-cap changer that's on that 2

transformer, and we basically send it a signal to 3

just regulate it, to regulate voltage coming out, 4

much like you would regulate your thermostat in 5

your home. And we cut that voltage down. The good 6

thing of this is we got no complaints from any 7

customers as a result of us reducing the voltage. 8

So that's a good thing. And Mr. Xanthakos was very 9

pleased with how this worked on our system. He 10

says he's going to call on it again in the future, 11

and I told him I hoped not in my lifetime, but it 12

was effective at getting us about 50 megawatts off 13

the system and really helped with the integrity of 14

the system, so we felt good about that. 15


Then he called and he said, "I need you to 17

shed 150 megawatts." "This is Control. I need you 18

to shed 150 megawatts of load." And so all the 19

preplanning that we do every June, we were going to 20

get tested on it for the first time. 21

So we went in and we began the same 22

processing, and just as we communicate remotely 23

with those transformers in those substations to 24

reduce voltage, so we started communicating with 25

jo.wheat

Typewritten Text

////

jo.wheat

Typewritten Text

tap


2/27/14


those breakers that you see in the substation -- 1

and each substation has about four to six breakers 2

in it, serving those circuits out of that 3

substation -- but this time, however, we're 4

deenergizing them. So we're opening up that 5

breaker, creating an open point, and everything 6

served downstream from it is going to be without 7

power. 8


There are the devices that we talked about. 10

If you'll look over here [indicating], there's your 11

breaker right there. That's what got the message. 12

And then we're able to monitor the system using 13

these SCADA devices that I've shown to you in 14

previous briefings 15


This shows you the blocks within our given 17

service territory. Y'all may view these in 18

districts. Well, we view them in districts, as 19

well, operating districts that we have. And you 20

will see that, initially -- and, of course, this 21

started at 7:49, but by 7:58, each of these blocks 22

reflect a circuit that was deenergized on our 23

system -- average time, 39 minutes -- as we went 24

through this rolling load shed. 25


2/27/14



Then came the next call at 8:27 -- based upon 2

Mr. Todd's generating output, and Mr. Xanthakos 3

trying to keep that seesaw balanced -- that we 4

needed to go in and shed 300 megawatts. 5


So once again, you can see that we went 7

through this process yet again, and you can see 8

across our service territory where we went in and 9

we shed the load. You'll look at some of the more 10

rural areas that you see down there to the 11

southwest of South Carolina -- excuse -- yeah, 12

southwest there, and you'll say, "Well not many 13

blocks there." Well, keep in mind, the whole 14

purpose of this is to shed load, so it's going to 15

be in some of your more urban areas that you're 16

going to be in shedding load, because if you shed 17

load in a rural area, you don't really knock off 18

many customers. You're not gaining any ground in 19

protecting that transmission grid. 20


An interesting thing happened through all 22

this. This is a substation breaker, and you can 23

see the lines coming in. These devices you see up-24

top, these ceramic coils, are called bushings. 25


2/27/14



I've been here 26 years and we haven't seen 2

this. Mr. Byrne showed you the weather that was in 3

place that morning? It was pretty cold. At the 4

same time, the wind was blowing. And at the same 5

time, there was high humidity. 6

What you see here is an icicle that developed 7

after condensation developed on a substation 8

bushing up in Saluda. And it migrated down that 9

bushing and shorted out that transformer. So, 10

Saluda -- there was a lot of talk that morning 11

about Saluda, and was it part of the rolling load 12

shed; and it was not. It was not. However, it 13

occurred during the same time and it was weather 14

related. 15


Therefore, when you look at the map now and 17

you see the customers that are out, you see the 18

yellow blocks there indicating the load-shed 19

sequence in the circuits that were interrupted, and 20

then the blue that you see right in that area 21

[indicating] represents Saluda. 22

So other things can happen on a system, as 23

they happened that night, before we went into that. 24



2/27/14


In addition to that, then came the call we 1

wanted to hear. Mr. Xanthakos told you about being 2

able to get emergency reserves back on the system, 3

so he came back and he directed Distribution 4

dispatch to begin restoring the load, and we 5

started going through that process. 6


And you can see the reduction in the blocks as 8

we started moving down from the peak of about 9

50,000 customers out. And you still have Saluda 10

out because that big transformer in that substation 11

had failed. 12


Then came the call at 10:27 for us -- to 14

request us to restore all of the load. 15


And you can see -- if you look, you'll see a 17

few little red blocks right in here and in here 18

[indicating], and you still have Saluda. 19

When you have cold weather and you have 20

components out in the field that are supposed to 21

swing open and swung shut -- like big arms on these 22

breakers or switches that have to swing in -- a lot 23

of times with the cold weather, they can get stuck, 24

because condensation can get on them, just as you 25


2/27/14


saw with the bushing that I demonstrated there, and 1

they can be a little difficult to close remotely. 2

That motor mechanism down in the bottom just can't 3

overcome the resistance that is there from the ice 4

and condensation. And so that's where we had to 5

send crews out into the field and manually close 6

those switches to pick up that load. 7


Then he came back and he said "Reset -- your 9

voltage reduction is ended, so you can go ahead and 10

set your regulators and your substations back to 11

normal," and that, in turn, is what we did. 12


That concludes the load-shed event, the impact 14

that it had on the customers, and concludes our 15

presentation. Thank you, very much. 16


Before Commission questions, we're going to take 18

about a five-minute break for Jo. 19

[WHEREUPON, a recess was taken from 11:08 20

to 11:12 a.m.] 21

CHAIRMAN HAMILTON: Okay, if we could, we'll 22

resume the ex parte. Thank you, very much, 23

gentlemen. It's been an excellent presentation 24

that we've heard from you, and I'm sure 25


2/27/14


Commissioners have some questions, and we'll open 1

it up for Commission questions. 2

COMMISSIONER RANDALL: Mr. Chairman, I've got 3

just a couple. 4

CHAIRMAN HAMILTON: Commissioner Randall? 5

COMMISSIONER RANDALL: Gentlemen, thank you. 6

That was a good presentation. I like the detail 7

and the hour-to-hour. That was very interesting. 8

I just had a couple of questions, because, from 9

things I'm learning about and things I've had some 10

dealings with in the past, I know about that day 11

being so cold, because I got a tankless water 12

heater from my local gas distributor, and it was 13

frozen, and it even has a heating unit in it, but 14

with that wind going. And I called, and I didn't 15

get any comfort or relief at that point in time, 16

until I got that pipe thawed. 17

So the couple of questions I had, and just for 18

my brains here: The firm -- when you're talking 19

about only being allowed to buy -- I know you only 20

purchase a certain amount of firm gas for units at 21

the time, and I know gas prices were high in 22

January. Is that something that's mandated to you, 23

or is that an internal policy that you only fix out 24

a certain amount of gas for that point in time? 25


2/27/14


MR. STEPHEN BYRNE [SCE&G]: Yeah, the 1

purchasing of firm gas supply, you have to actually 2

purchase the space on the pipeline -- 3

COMMISSIONER RANDALL: Right. 4

MR. STEPHEN BYRNE [SCE&G]: -- and then you 5

purchase the molecules of gas. So it's really the 6

space on the pipeline that we're purchasing or 7

reserving. That's a balancing act, so you don't 8

want to overpay for things you don't generally 9

need. Now in the summertime, spring, fall, we 10

generally don't need firm transmission; there's 11

plenty of gas available. Really, it's generally a 12

wintertime situation. Increasingly, it is becoming 13

a summertime situation, with the number of gas 14

generators. Obviously, people aren't using a lot 15

of gas to heat their homes in the Northeast in the 16

summertime, but with the increasing amount of 17

combined-cycle gas generation, we're starting to 18

see flow restrictions even in the summertime. So 19

it really is a balancing act. 20

Now, last year, we did buy an additional 21

10,000 dekatherms a day for the Urquhart Station. 22

So I think we had 51,000 dekatherms a day reserved 23

at Urquhart, and we're up now to 61,000, but we can 24

only buy that when it becomes available. So we 25


2/27/14


evaluated it when it became available last year, 1

and decided we didn't want to buy the additional. 2

But it would take what they call an open season on 3

one of those pipelines for the suppliers to say, 4

"Hey, we've got more firm transportation available. 5

Do you want to buy it?" Right now, we couldn't buy 6

it. So it is a balancing act up front, and we 7

continue to monitor it; and if we wanted to buy 8

more today, we couldn't do it. 9

COMMISSIONER RANDALL: And another gas 10

question: Were your interruptible customers -- did 11

you say they were only down about the same amount 12

of time -- that average 39 minutes -- with that? 13

MR. KELLER KISSAM [SCE&G]: Are you talking 14

about the electric side or the gas side? 15

COMMISSIONER RANDALL: On the gas side. 16

MR. KELLER KISSAM [SCE&G]: Our gas 17

interruptible customers -- and there are a variety 18

of them -- they were interrupted the Wednesday 19

prior to this, and they were off. And they have 20

interruptible categories that go 9, all the way up 21

through 3F, and 3D, and even to the hospitals. And 22

what happened is they were curtailed on Wednesday 23

due to the weather that we had. There was a little 24

release that came that weekend when temperatures 25


2/27/14


moderated and you went into the weekend and the 1

demand fell off. But they were curtailed. That's 2

what makes Mr. Todd's balancing act so difficult at 3

plants, such as Urquhart, as he's got to balance 4

what is flowing in the pipe, as far as his firm, 5

knowing that his interruptible or release capacity 6

he could have access to, to put that unit entirely 7

on gas, has been curtailed. He also has a unit, 8

Hagood, down in Charleston, that's a Category 9, so 9

it was not available to run on natural gas, which 10

makes it even more difficult. 11

And what Mr. Byrne is saying, you have to 12

balance that, because when you have firm gas, you 13

pay a monthly demand component and then you pay the 14

commodity. So it's how much of that demand paying 15

you're willing to live with, from a prudency 16

standpoint, to be able to have the volumetric there 17

and for a reasonable amount of time in order to be 18

able to operate your units. So they do a great job 19

of kind of balancing that, both long term and short 20

term. 21

COMMISSIONER RANDALL: Thank you. I know that 22

is a balancing act. And one more just quick 23

question. On shared reserves, when you're with the 24

VACAR group and you've got that number -- and, 25


2/27/14


really, this weather event sort of shot a hole in 1

some of the theory behind that -- do you think, 2

with the way that the weather seems -- we seem to 3

be in a period of much more, much wider swings, I 4

guess, in weather events, do you think that you're 5

going to get any NERC action on trying to adjust 6

that kind of reserve action that you're going to 7

have? 8

MR. LEE XANTHAKOS [SCE&G]: I don't think 9

we're going to get that. Keep in mind, we were 10

carrying -- if the NERC rule is the largest unit, 11

which is around 1100 megawatts, if you take the 12

1600 or 1700 we're going to carry, plus the 13

additional 3000, we were at -- you know, if you do 14

the math -- five times the NERC requirement. So 15

even if they changed it to twice as much -- 16

COMMISSIONER RANDALL: You'd still be well 17

within that, yeah. 18

MR. LEE XANTHAKOS [SCE&G]: -- it would be -- 19

they couldn't change it high enough. If they 20

changed it that high, nobody would ever generate 21

electricity; they'd all be in reserves. 22

COMMISSIONER RANDALL: Yeah. 23

MR. LEE XANTHAKOS [SCE&G]: So I don't think 24

that's going to change. 25


2/27/14


COMMISSIONER RANDALL: Thank you. 1

CHAIRMAN HAMILTON: Commissioner Whitfield. 2

COMMISSIONER WHITFIELD: Thank you, Mr. 3

Chairman. 4

Thanks to all of you, all four of you, for a 5

very informative presentation. I'm a very visual 6

person, and you made that about as visual as you 7

could make it without us physically being at the 8

facilities and on-site. That being said, I know 9

we've always prided ourselves on reliability. We 10

talked about our reliability here in the Southeast, 11

and I know this Commission takes a lot of pride in 12

reliability, and I know you do, as well. And while 13

we had the snow event and many more people were 14

impacted, I was much more nervous with this event 15

right here. And I was in the law library with a 16

lot of folks here, and we were very much nervous 17

and watching how you handled it. But you did a 18

great job explaining this. But I want to ask a 19

question -- it looks like all the planning, you 20

explained every step. Then you had the 21

chronological explanations, each of you did. And 22

what I would like to ask -- Mr. Byrne started to go 23

down that path just a little bit in his 24

presentation, and Mr. Todd mentioned the switch, 25


2/27/14


the pressure switch, and you answered one of 1

Commissioner Hall's questions, and the pressure 2

switch with Williams Station and then the problems 3

-- non-weather-related problems that you had 4

mechanically at Urquhart. And Mr. Byrne made a 5

comment that we can protect these things but with 6

some cost. And I guess my question is, is there 7

not something lesser that could be done, 8

particularly as it pertains to these switches and 9

just protecting them, maybe, rather than protecting 10

the whole area? What could be done? And the 11

notion that Mr. Byrne suggested, I guess you're 12

talking something astronomical, the way you hinted 13

there. But if you two, Mr. Byrne or Mr. Todd, 14

either one, could answer that question, I'd 15

certainly like to hear that. 16

MR. JOSEPH TODD [SCE&G]: Yeah. If we are 17

going to -- what Mr. Byrne was referring to, I 18

believe, was that if we went and put an enclosure 19

around all the plants -- that's the extreme that we 20

would go to, to really bulletproof everything -- 21

that would be a lot of money. Cope Station does 22

have an enclosed boiler, and so we really don't 23

have near the issues with enclosed boilers that we 24

do with ones on the outside, like Urquhart and 25


2/27/14


Williams. McMeekin's enclosed; Cope's enclosed. 1

So that's kind of where we start from. 2

There are things we can do, and we will do. 3

One of the things we're doing right now, we're in 4

the early stages, but we're going to do a complete 5

review of heat-tracing systems at all of our 6

facilities. Not just Urquhart, not just Williams, 7

but we're going through all of them. We're going 8

to go through, look at the technology, look at the 9

age of the circuits. And if we need to make any 10

upgrades in order to improve reliability in those 11

areas, we're going to do it. 12

So that's probably one of the main things 13

we're going to do as we go through this process. 14

And again, we're not to the end yet, so we don't 15

know what the answers are going to be, but I would 16

expect we would make some physical modifications as 17

a result of this. 18

COMMISSIONER WHITFIELD: So those are the 19

modifications, Mr. Todd, that you could probably do 20

without getting the gold plate, so to speak, that 21

you were talking about, completely enclosing it. 22

But I think that would -- I mean, I just wondered 23

about that, because you've got such a long history 24

here of reliability. And, of course, as Mr. Kissam 25


2/27/14


explained, once he was asked to do what he had to 1

do, the system did work as planned. And, anyway, I 2

do appreciate this presentation and explaining to 3

us what happened on January 7th. 4


CHAIRMAN HAMILTON: Thank you. 6

Commissioners? Commissioner Howard. 7

COMMISSIONER HOWARD: Good morning. Again, I 8

appreciate the presentation. You did a great job. 9

Either one of you: You said you were looking at 10

lessons learned. So far, what have you identified 11

as lessons learned from this? 12

MR. JOSEPH TODD [SCE&G]: I think the one I 13

just referred to was one. We're going to go 14

through and look at the heat-tracing systems. 15

Obviously, this was a driver in the event. And I 16

think, right now, that's the main thing that we've 17

identified. 18

We also looked at -- we had -- another example 19

would be, we had issues at some plants with 20

instrument air systems. It didn't affect 21

reliability on the plant; it was really more of a 22

nuisance to operators. But those systems were 23

freezing up a bit, too, in some locations, because 24

the instrument air had moisture in it. It would 25


2/27/14


get through and it would kind of cause the valve to 1

stick up. So we're going to go back and look at 2

more instrument air drying to put in those systems, 3

too, just to keep that moisture out of it. 4

So those are two examples. 5

COMMISSIONER HOWARD: Is that a costly 6

process? I mean, how -- will it be very little? I 7

mean, I guess my question is, how much impact would 8

that have on ratepayers? I know you can't answer. 9

You don't -- I know that. But is it a costly 10

process? Let me ask it that way. 11

MR. JOSEPH TODD [SCE&G]: Personal opinion, I 12

think we'll probably be in the single-digit 13

millions range, as opposed to 10-millions. 14

COMMISSIONER HOWARD: Okay. 15

MR. STEPHEN BYRNE [SCE&G]: One of the 16

examples might be that we have heat-tracing 17

circuits that just indicate that power is 18

available. That's generally on our older stations. 19

If you go to some of our newer plants, the heat-20

tracing circuits there will give you "power 21

available," but it will also show you the current 22

is actually flowing. Had we had one of those types 23

of heat-trace circuits, the indications there at 24

the Williams Station, we probably would have known 25


2/27/14


that the current was not flowing in that circuit. 1

So what we’ve got at Williams was, yep, the circuit 2

is energized; we just didn't realize that the 3

current wasn't flowing. There was obviously an 4

internal fault to that system. But there are heat-5

tracing controllers that will show you that actual 6

current is flowing. So we'll have to do some of 7

those modifications, as Joe points out. 8

It will be millions of dollars. I know it 9

doesn't sound like it's much to replace a 10

controller and replace heat tracing, but it will be 11

millions of dollars when we get through with all of 12

the circuits. So we're doing an evaluation of 13

those circuits now. And some of the insulation, 14

we're going to look at, as well. We think there 15

may be some improvement in insulation. 16

We're also not finished with the lessons 17

learned, because one of the things we want to do is 18

benchmark some other utilities. We're aware of the 19

fact that they had some significant problems in 20

Texas. I think Joe has got a benchmarking trip 21

slated for Texas in April. 22

MR. JOSEPH TODD [SCE&G]: Early April, yes, 23

sir. 24

MR. STEPHEN BYRNE [SCE&G]: Early April. So 25


2/27/14


we're trying to learn the lessons that they got 1

from some of their facilities. So those are the 2

kind of lessons that we learned. 3

I've also seen some reports -- I think it was 4

in the Charleston media -- about, "Why don't they 5

just do what they do in nuclear plants, because 6

none of the nuclear plants came off-line during 7

this polar vortex, yet, you know, hundreds of other 8

plants came off-line." And with nuclear, we do 9

basically bulletproof the plants against the cold, 10

so you don't see outside, you know, reactor 11

buildings and turbine buildings and those kind of 12

things at nuclear facilities. But they do spend a 13

lot more money on the heat tracing. 14

So this is the kind of an issue that comes up, 15

for us, once every couple of decades, and the 16

question then is -- it's another balancing act -- 17

how much do you want to spend to protect the plants 18

against cold that you're probably not going to see 19

for 20 or 30 years? 20

COMMISSIONER HOWARD: I know -- and you know a 21

lot better than I do -- you caught a lot of heat 22

from the media. And I guess that's a bad choice of 23

words. 24

[Laughter] 25


2/27/14


But it was simple things; they were saying, 1

you know, "They could've bought a space heater and 2

eliminated this." I mean, that was one of the 3

letters to the editors, or something like that. 4

How do you respond to that type of simplistic 5

criticism? 6

MR. STEPHEN BYRNE [SCE&G]: Well, first of 7

all, we're not going to respond to all of those 8

kinds of -- 9

COMMISSIONER HOWARD: Well, you know. 10

MR. STEPHEN BYRNE [SCE&G]: -- things, but the 11

notion that we could have simply purchased space 12

heaters and put them out -- we did, in some of our 13

locations, based on prior experience, take some 14

actions that were not ordinary. Joe pointed out a 15

couple of those. We have louvers on our plants for 16

airflow, and we blocked the louvers to prevent the 17

cold air from coming in, because of the problems 18

we've experience in the past, that didn't recur. 19

The problems that we saw that took these plants off 20

were new issues to us. So had I had a space heater 21

available -- and we do -- I wouldn't have put them 22

in these locations, because I had no reason to 23

suspect that they were a problem. Obviously, I do 24

now. 25


2/27/14


So in the aftermath of that issue, we did put 1

those space heaters in some of those locations. I 2

think we talked about that, and some people 3

misconstrued that as "They had the space heaters; 4

all they had to do was put them in those locations 5

and we wouldn't have had the problem," which isn't 6

really the case. 7

So I understand that people don't get what it 8

is that we're talking about, but if you say it's a 9

corrective action to now put a space heater here, 10

then they say, "Well, if you would've just put a 11

space heater there in the first place, it would've 12

solved the problem," but we didn't know to do that 13

in the first place. We've never experienced 14

problems at these locations like this. 15

COMMISSIONER HOWARD: I have to admit that I'm 16

getting probably the dates mixed up, but did many 17

people go off-line during the January 7th outage? 18

MR. STEPHEN BYRNE [SCE&G]: Did many people go 19

off-line? I think -- 20

COMMISSIONER HOWARD: I mean, besides the shed 21

load. 22

MR. STEPHEN BYRNE [SCE&G]: No. 23

COMMISSIONER HOWARD: So just the shed load 24

were the only ones that went off-line. 25


2/27/14


MR. STEPHEN BYRNE [SCE&G]: We had -- the 1

winds caused a small number of problems in the 2

early morning hours between the 6th and the 7th, 3

that Mr. Kissam's distribution crews were taking 4

care of. And we basically had most of those 5

restored at the time we came to the load-shedding 6

event. And one of the issues we had, as he pointed 7

out, in that Saluda substation, we had the one 8

switch that was impacted by freezing. Other than 9

that, we didn't have anybody out, other than for 10

load-shedding issues. 11

COMMISSIONER HOWARD: You said the average was 12

39 minutes. Do you know what the longest someone 13

was out because of the load shedding? 14

MR. KELLER KISSAM [SCE&G]: The longest 15

someone was out was approximately an hour and 49 16

minutes, and the reason for that was if we could 17

not energize remotely when you roll them through, 18

and if you had to send -- if you had to scramble a 19

crew to get to that location in order to get them 20

back on. So that would've been the longest someone 21

would've been out. 22

COMMISSIONER HOWARD: How do you prioritize 23

your load shed? 24

MR. KELLER KISSAM [SCE&G]: Every June, we go 25


2/27/14


in and look at the circuits, the hundreds of 1

circuits that we have. We put them in those 2

categories of 1, 2, and 3. And you basically -- 3

the only thing you take into consideration is 4

public health and safety. So your human-needs 5

type facilities, such as your hospitals, your 6

water treatment plants, your wastewater plants, 7

those are going to be the last that you want to 8

take off in an event such as this. In the middle, 9

you have -- 10

COMMISSIONER HOWARD: I guess I meant -- I 11

understand. I guess I meant in Category 1. Do you 12

-- you didn't have to go any farther than Category 13

1, did you? 14

MR. KELLER KISSAM [SCE&G]: No, sir, we got 15

some Category 2s off. 16

COMMISSIONER HOWARD: Did you? 17

MR. KELLER KISSAM [SCE&G]: Yes, sir. 1s and 18

2s. We didn't get to 3s; however, there were two 19

hospitals that were impacted, but we had actually, 20

physically -- people physically located where they 21

were communicating with these customers, and in the 22

event that they were out, we quickly restored that 23

circuit back and energized it, so it would've come 24

right back on, because, you know, you do it in June 25


2/27/14


of every year, and you have changes that occur 1

after June. I mean, we went from June to January, 2

with this event. So, you know, if you update every 3

June, you're going to have some one or twosies out 4

there that you're going to have to deal with, and 5

we dealt with them and got them right back on. 6

But once we get into a Category 1, I mean, we 7

just start. And we start -- we go in through those 8

1s and we start cutting them off. When he calls in 9

and he ups it to 300 megawatts instead of 150 10

megawatts, we pretty much are going to get into the 11

2s. So it was 1s and 2s that we brought off, and 12

everybody kind of comes off at the same time. 13

COMMISSIONER HOWARD: You know, being cynical 14

and just playing the devil's advocate, I look at 15

chart number 49 -- 16

MR. KELLER KISSAM [SCE&G]: Yes, sir. 17

COMMISSIONER HOWARD: -- and I'm saying, "Hey, 18

this is the first load shed. Look at us in 19

Charleston; we've got some. But look at Columbia. 20

Columbia's where SCE&G headquarters is, and Scott 21

lives in Columbia, and all that. 22

[Laughter] 23

And they're clear. But, you know, the poor 24

people who live in Charleston, I mean, you just -- 25


2/27/14


MR. KELLER KISSAM [SCE&G]: Yes, sir. And 1

there were other slides that I could have shown 2

you. There are other -- 3

COMMISSIONER HOWARD: I'm just teasing. 4

MR. KELLER KISSAM [SCE&G]: Yes, sir. 5

COMMISSIONER HOWARD: That doesn't deserve an 6

answer. 7

MR. KELLER KISSAM [SCE&G]: Yes, sir. But we 8

would cut Mr. Scott off first. 9

[Laughter] 10

But you need to understand, seriously, what 11

you saw was a moment in time. And what we tried to 12

demonstrate through those slides that we showed you 13

is that it is widespread across our system. And 14

what I mentioned earlier is the urban areas is 15

where you have your most concentrated load, and 16

that's where you're going to pick up the most 17

advancement when you're trying to protect that 18

transmission grid. 19

COMMISSIONER HOWARD: All right. Probably my 20

next-to-last question, but you went from 120 to 118 21

and there was no noticeable effects or complaints? 22

MR. KELLER KISSAM [SCE&G]: That was on 23

voltage reduction, yes, sir. 24

COMMISSIONER HOWARD: Voltage reduction. How 25


2/27/14


far do you think you could've gone before -- you 1

know, me being a residential consumer, when would I 2

have noticed that there was a difference in my 3

electric service? How far -- 4

MR. KELLER KISSAM [SCE&G]: I don't know if 5

you could go too much further. You might could get 6

another 2 percent out of it, but then you've got to 7

understand that your house is probably going to be 8

okay, but if you've got a commercial establishment 9

out there with a motor, such as that, then the 10

harmonics are going to get out of whack and they're 11

going to start having problems. And that's what 12

you've got to make sure. You can push the 13

envelope, but you can only push it so far based 14

upon what you're actually serving off those various 15

circuits that you reduce the voltage on. And you 16

don't want that to happen. 17

COMMISSIONER HOWARD: All right. My last one 18

is, there were some questions about keeping 19

Fairfield Pumped Storage at a full level. I guess 20

knowing this was coming up, why wasn't or was it at 21

full level prior to January 7th? 22

MR. LEE XANTHAKOS [SCE&G]: It was used on 23

January 6th. If you'll remember the slide that Mr. 24

Byrne showed, the loads on January 6th were 25


2/27/14


relatively low. There was a swing of about 2000 1

megawatts from the low on the 6th to later on on 2

the 7th. Going back to the minimums that were 3

talked about, we couldn't have other plants on-line 4

then, because we would've had too much power on our 5

system. So a lot of the units that we were 6

counting on the 7th were actually brought on during 7

the day of the 6th, and while those were getting 8

brought on, we were using Fairfield Pumped Storage 9

to generate with, to serve our customers. So, as 10

those plants were coming on, we were increasing the 11

level of Fairfield. 12

COMMISSIONER HOWARD: That's it. Thank you, 13

very much. Again, it was a great presentation. 14

CHAIRMAN HAMILTON: Commissioner Fleming. 15

COMMISSIONER FLEMING: Well, good morning. As 16

you can tell from my spontaneous response earlier, 17

this was a very exciting session. I would have 18

never imagined such, especially coming from the 19

control room area, but -- and it really sounds like 20

you all did an incredible job with quite a 21

challenge. And I appreciate your coming before us, 22

and the hard work that you did during this entire 23

event. 24

I do have -- I want to ask one question. I 25


2/27/14


don't believe Commissioner Howard lost his power. 1

Now, if all the poor people of the Charleston area 2

lost their power, how did this one Commissioner -- 3

[Laughter] 4

-- get served? Are you -- 5

COMMISSIONER HOWARD: That doesn't deserve an 6

answer. 7

[Laughter] 8

MR. KELLER KISSAM [SCE&G]: I assure you, we 9

don't take that into consideration. 10

[Laughter] 11

CHAIRMAN HAMILTON: I've got a feeling, if you 12

did, he'd be the first to go. 13

[Laughter] 14

COMMISSIONER FLEMING: He just got to Mr. 15

Scott's level. 16

Well, seriously, getting back to this, I was 17

just sitting here during this presentation, and 18

everything seems to be going to gas power 19

generation now, and that was -- it sounds like to 20

me that that was a big issue, especially when it 21

came to reserves and extra gas that you needed that 22

wasn't firm supply. I guess -- and with the 23

extreme weather events that are becoming very 24

common, things that were 100-year events are 25


2/27/14


happening quite more frequently, and 10- or 20-1

years becoming shorter times, is that an issue that 2

we should be concerned about? And secondly, if 3

you'd have had the additional extra two units on at 4

V.C. Summer, would the situation have been 5

different? 6

MR. STEPHEN BYRNE [SCE&G]: I think, 7

obviously, with the two extra units on at V.C. 8

Summer, we would've had a lot more capacity to 9

supply the load, so obviously the situation 10

would've been different. Now, every situation is 11

going to be unique: how we stage the plants. The 12

fact that you can't just keep plants, you know, 13

hovering there in anticipation of a load sometimes 14

plays a factor. 15

But I think more to the point is that our 16

advocacy of a balanced generation portfolio -- I 17

think these kind of scenarios demonstrate that 18

that's a good philosophy. So we don't ever want to 19

put all of our eggs in one basket. We already have 20

about 30 percent capacity in natural gas, so we're 21

not looking at increasing that dramatically. So 22

I'm not saying we won't build any more natural-gas-23

fired plants. In all likelihood, in the far future 24

years, we may. But I think that strategy we've 25


2/27/14


outlined where we're going to have about 30 percent 1

nuclear, 30 percent gas, and 30 percent coal, is 2

going to be one that, if we have problems with one 3

fuel source, you can swap to the other sources. I 4

think it's a good one. 5

COMMISSIONER FLEMING: Okay. And -- 6

MR. KELLER KISSAM [SCE&G]: And, Commissioner 7

Fleming, just to add to that, I think you make a 8

very valid point, not just from a generation 9

standpoint on gas. As you know, the original 10

transmission interstate pipelines came into South 11

Carolina in the 1950s, as they have in other 12

states. To add capacity to those pipes is a big 13

issue and a challenge for all of North America. 14

First of all, you can't get right-of-way to put new 15

lines in, because it's a very onerous process as 16

far as dealing with right-of-way acquisition. The 17

second thing is, these pipes are getting some age 18

on them, and there's only so many of these 19

facilities that you can cram into the existing 20

right-of-way that you have. And all of those are 21

issues. You can have all the cheap gas fracked in 22

Pennsylvania that you want to, but if you don't 23

have the capacity to get it to markets in a 24

reliable -- from a reliable standpoint, and 25


2/27/14


particularly during circumstances such as this, 1

then it's of no use or no value to you. So you've 2

hit on a very valid point that really brings out 3

not just this but every day, with regards to 4

natural gas capacity. 5

COMMISSIONER FLEMING: So if we're going to 6

more natural gas, we've got to build the ability to 7

get the gas to the -- 8

MR. KELLER KISSAM [SCE&G]: Yes, ma'am. 9

COMMISSIONER FLEMING: -- customer. 10

MR. KELLER KISSAM [SCE&G]: It's just like 11

traffic. You've got to put roads -- 12

COMMISSIONER FLEMING: But that's -- 13

MR. KELLER KISSAM [SCE&G]: -- and bridges in 14

to be able -- 15

COMMISSIONER FLEMING: -- restricted -- 16

MR. KELLER KISSAM [SCE&G]: -- to handle it. 17

COMMISSIONER FLEMING: -- now. 18

MR. KELLER KISSAM [SCE&G]: Yes, ma'am. The 19

same thing with the pipes. If we're going more to 20

gas, then that's the big challenge for North 21

America, is the capacity in interstate pipelines to 22

get it to the various markets where the users are. 23

COMMISSIONER FLEMING: Okay. And I wanted to 24

ask a question about reserves. There seems to be a 25


2/27/14


tendency to backing down on the amount of reserves. 1

And I guess I'll go back to these extreme weather 2

events again. I know that all of the companies had 3

hit their reserve margin -- around us, I believe. 4

I know Duke came in, and they said they had tapped 5

out, as well. So what is your opinion about the 6

reserve margins, and do we need to reevaluate 7

whether it should be lowered or not? 8

MR. STEPHEN BYRNE [SCE&G]: Yeah, we do 9

reevaluate the reserve margin requirements every 10

year when we submit our integrated resource plan. 11

And there was a tendency, I think, nationwide, to 12

scale back on reserve margins. Our reserve margins 13

were actually increased -- I think it was two years 14

ago. We went up to a reserve margin band of 14 to 15

20 percent, whereas before that we were a little 16

lower; I think it was 12 to 18. So we've actually 17

increased our reserve margin requirements. 18

Now, that's a planning reserve, and with that 19

you would assume that while you plan to have 20

somewhere between 14 and 20 percent reserve margin, 21

there may be a plant out of service at any one 22

point in time. So whether that's planned or 23

unplanned maintenance or a fuel issue, you always 24

plan for some of those facilities to be out of 25


2/27/14


service at any given point in time. 1

But the VACAR reserves that we talked about 2

are a terrific tool to us. And I think as Lee 3

pointed out, it would be difficult to imagine 4

almost 1700 megawatts of reserves, plus an 5

additional 3000, not being enough in the Southeast. 6

That still seems to be incredible to me. 7

But we evaluate our reserve margins 8

constantly. We can certainly up it, but again, if 9

you up it, it comes with a cost, because you then 10

have to plan for more facilities to be available to 11

you. So it's -- again -- another balancing act. 12

But we did increase our reserve margin a couple of 13

years ago. 14

COMMISSIONER FLEMING: So, I mean, this truly 15

was a perfect storm in all regards, for you 16

personally and for the region, as well. 17

MR. STEPHEN BYRNE [SCE&G]: It was. And our 18

goal is always to avoid those situations that Lee 19

presented, where they had the Northeast and the 20

Southwest blackouts. And we did that. So the 21

system actually did perform its intended function, 22

the way it should have. 23

COMMISSIONER FLEMING: And even though, 24

apparently, you got some bad press for this, didn't 25


2/27/14


you say that the customers, you really didn't -- 1

did I understand you to say that they were very 2

understanding of the situation? 3

MR. KELLER KISSAM [SCE&G]: What we talked 4

about with the customers is when we reduced the 5

voltage, which was the initial, which got us about 6

56 megawatts, when we cranked down the regulators 7

on those transformers in those substations, we 8

didn't have any customer issues from that. We 9

didn't have anybody call into the call center and 10

say, "Hey, my lights are dim," or, "My lights are 11

flickering." We had no commercial customers call 12

in saying, you know, "My motor's running 13

backwards," or anything along those lines. So from 14

that standpoint, no problems. 15

From a press standpoint with the media, you 16

know, once we were able -- you know, our whole 17

focus on this was -- the people sitting at this 18

table -- was to stabilize that system and protect 19

that system. And then, communication to customers, 20

that's probably a lesson learned too, as far as 21

trying to get information out to them in a quicker 22

fashion. I mean, everybody's on Twitter and social 23

media now, and that can certainly be a means of 24

that. But as far as a press release, you've really 25


2/27/14


got to know exactly what you've got going on. You 1

don't want to panic the public into -- you know, 2

we're having rolling blackouts, and people panic 3

over that. But what you want them to understand is 4

"This is a controlled process. This is the reason 5

why we're doing it." And we followed up with a 6

press conference, and once we had that press 7

conference, a lot of the negativity -- other than, 8

you know, one that Commissioner Howard mentioned 9

about "Why don't you just put the heaters in the 10

right place? It seems like a simple solution." 11

You know, those pretty much went away once they 12

were aware that it was a controlled situation, and 13

particularly when the situation had ended. 14

COMMISSIONER FLEMING: So you would -- you're 15

going to look at your communication, then, with 16

your customers -- 17

MR. KELLER KISSAM [SCE&G]: Yes, ma'am. 18

COMMISSIONER FLEMING: -- to see if that -- 19

MR. KELLER KISSAM [SCE&G]: And I will tell 20

you, that morning in my conference room -- and I 21

was communicating in the field, as well as with Mr. 22

Xanthakos -- you know, we had our PR people in 23

there. And it's just -- I think we've got to be a 24

little quicker with regards to getting somewhat of 25


2/27/14


information out there, even though it may not be 1

complete information. 2

And that's something else you have to balance. 3

Can they scroll things on the bottom of the TV? 4

Exactly how can we get it out there? So the first 5

we did was social media, then we posted things on 6

our website. But as far as official communication 7

to the media, it pretty much occurred when we had 8

the press conference, which was a little later on 9

in the day. 10

COMMISSIONER FLEMING: Uh-huh. We watched 11

that, some of us did. Well, I was just -- I really 12

appreciate the information that you gave. I think 13

this would make a good documentary feature to maybe 14

enlighten the public about what goes on in these 15

events. 16

MR. KELLER KISSAM [SCE&G]: Well, we can be 17

filmed, but you're going to have to -- there can be 18

no audio, I can assure you, with what we had going 19

on that morning. 20

[Laughter] 21

COMMISSIONER FLEMING: Well, if it's being 22

filmed, you can hold your emotions maybe a little 23

more. Thank you. 24

CHAIRMAN HAMILTON: Thank you, very much. Any 25


2/27/14


other -- 1

COMMISSIONER McGEE: Mr. Chairman. 2

CHAIRMAN HAMILTON: -- questions, 3

Commissioners? Commissioner McGee. 4

COMMISSIONER McGEE: Thank you, sir. 5

Again, not to beat a dead horse, but I 6

appreciate the presentation. I know -- just to 7

piggyback onto what Commissioner Fleming was saying 8

-- from a consumer or customer standpoint, the 9

information is very enlightening. It's obvious how 10

seriously the company takes these sorts of things. 11

Y'all were very well prepared, but, as you said, 12

mother nature is still very unpredictable when 13

things get colder than you expect or that sort of 14

thing. I guess, just for me, especially since I'm 15

kind of one of the new folks here, your top 16

priority was keeping a cascading failure from 17

happening. Just out of curiosity, what would that 18

have looked like, worst-case scenario? 19

MR. LEE XANTHAKOS [SCE&G]: Worst case would 20

probably have brought down North Carolina and 21

Georgia, maybe part of Virginia, part of Tennessee. 22

I doubt it would've gone to Alabama or Florida. 23

That's what I'm guessing. 24

COMMISSIONER McGEE: Yeah. And I guess what 25


2/27/14


my question is, if you think about where it could 1

have gone, you know, from an average of 39 minutes 2

to hang tight, you know, to me that's to be 3

commended. And just one last thing I had. I think 4

we kind of talked about it a little bit. I know 5

since I've been on the job, climate change seems to 6

be a hot topic right now. You know, every storm 7

has a name now, whether it's a snow shower or a 8

hurricane. You know, California's dealing with a 9

drought. What are -- and I know y'all talked about 10

talking with some of your industry folks and 11

sharing ideas. What is some of the buzz about 12

climate change and how it's going to affect how you 13

prepare going forward? 14

MR. STEPHEN BYRNE [SCE&G]: Well, I think 15

we've been looking at -- whether you call it global 16

warming or you now call it climate change, we've 17

been looking at those and how they affect us for a 18

long period of time. And we made a decision many 19

years ago that nuclear was the right answer. So 20

whether it's climate change or global warming, 21

nuclear plants don't have any of those emissions. 22

So the gas plants have some, less than coal. And 23

so what you've seen us do is you've seen us scale 24

back on coal and increase our commitment to 25


2/27/14


nuclear. You know, so we see that as the answer 1

going forward. 2

Now with regard to what it's going to do to 3

our facilities, you know, that's something that 4

we're constantly evaluating. We haven't yet seen 5

the water changes, the water level changes that 6

people are talking about. Certainly, we've seen 7

drought here in South Carolina. In fact, I think 8

while we were going through our initial set of 9

hearings for construction of the nuclear plant, we 10

were in a drought at that point in time. 11

Obviously, that's not the case any longer. We've 12

got as much water as we can handle. 13

So, you know, our planning for things like 14

climate change really involve how we're going to 15

live up to our commitments to it. What we do 16

anticipate is that, at some point, we'll see more 17

regulation -- or legislation, but probably 18

regulation -- out of the EPA relative to climate 19

change, specifically dealing with carbon. 20

So they've already had some carbon regulations 21

for new sources. We anticipate carbon regulations 22

for existing sources. But, again, if you have a 23

nuclear strategy, that gets you away from that. So 24

as a hedge to that kind of regulation, it's build 25


2/27/14


nuclear. 1

MR. KELLER KISSAM [SCE&G]: And Commissioner 2

McGee, the other thing is, talking about the 3

violent weather we've had, we're very proud of the 4

mutual assistance arrangements we have through, 5

particularly, the Southeastern Electric Exchange 6

with fellow utilities. One of the things we're 7

going ahead and doing is routing crews to those 8

impacted areas in a quicker fashion, and that's 9

something we try to do on our system to get ahead 10

of that curve. 11

I know the other Commissioners hear about it 12

on a regular basis and you'll hear about it coming 13

up, and it will be tree trimming. And we have to 14

go out and we have to try to harden our system as 15

best we can. Maybe not to have customers, you 16

know, their power not going out, but to have the 17

duration of that outage as small as it can be. If 18

we had to send tree crews in to remove trees -- and 19

that was one of the things that, when we had 20

linemen go up into Connecticut with these winter 21

storms they had last year, the guys said they sat 22

around for a week and a half and did absolutely 23

nothing, and were on the payroll of those utilities 24

up there, until the tree crews could go in there 25


2/27/14


and remove all of the vegetation. 1

So we've got to be focused and vigilant -- and 2

it's a balance with aesthetics. But we've got to 3

be focused and vigilant in what we do every day, as 4

far as installing SCADA, as far as vegetation 5

management, as far as circuit inspection and 6

correction. You'll see our crews out there 7

changing out poles. Those are the things that we 8

do every day to try to harden the system as much as 9

we possibly can, and we will continue to do so, and 10

then we'll rely on our neighbors, because, just 11

like you have sharing of energy back and forth 12

across state lines, one of the most valuable 13

resources that we share across state lines is that 14

of a lineman, in order to get people in here and 15

get people's power back on. 16

COMMISSIONER McGEE: Thank you, gentlemen. 17

That's all I have, Mr. Chairman. 18

CHAIRMAN HAMILTON: Anything else? 19

[No response] 20

Mr. Byrne, it sounds like you were almost 21

caught with a double whammy when you had the 22

generation units going off at the same time you had 23

the weather issue. If the non-weather issue 24

might've hadn't occurred, would load shedding have 25


2/27/14


been necessary still? 1

MR. STEPHEN BYRNE [SCE&G]: No. No. Had the 2

plants stayed on-line that came off because of the 3

weather-related issues? No, there would not have 4

been any load shed. 5

CHAIRMAN HAMILTON: And Lee would not have 6

started his graying process there. 7

MR. STEPHEN BYRNE [SCE&G]: That's right. 8

[Laughter] 9

CHAIRMAN HAMILTON: Well, again, I want to 10

thank each of you for the excellent job you've 11

done. 12

MR. MELCHERS: We've got one more question. 13

CHAIRMAN HAMILTON: We've got another 14

question? I'm sorry, I apologize. 15

VICE CHAIRMAN HALL: That's okay. Thank you, 16

Mr. Chairman. 17

I just have two. Mr. Xan- -- 18

MR. LEE XANTHAKOS [SCE&G]: Lee. 19

[Laughter] 20

VICE CHAIRMAN HALL: Sorry. -- Xanthakos, is 21

that right? 22

MR. LEE XANTHAKOS [SCE&G]: Yes. 23

VICE CHAIRMAN HALL: Okay, I'm sorry. I just 24

wanted -- when you got the emergency power from the 25


2/27/14


two companies that were outside of VACAR, were they 1

merchant companies? I didn't -- I mean, I just -- 2

if the whole region was experiencing the same 3

issues, I was just wondering where that came from. 4

MR. LEE XANTHAKOS [SCE&G]: No, they were not 5

-- one -- we got power from one company that was 6

not within the VACAR reserve-sharing group. 7

VICE CHAIRMAN HALL: Oh, okay. And it was -- 8

MR. LEE XANTHAKOS [SCE&G]: It came from the 9

west. 10

VICE CHAIRMAN HALL: Oh, okay. 11

MR. LEE XANTHAKOS [SCE&G]: It came from the 12

west of us. So if you look at a map of VACAR -- 13

VACAR stands for Virginia-Carolinas? 14

VICE CHAIRMAN HALL: Uh-huh. 15

MR. LEE XANTHAKOS [SCE&G]: So, Virginia and 16

both of the Carolinas. -- this came from the west 17

of us from another company. 18

VICE CHAIRMAN HALL: Oh, okay. Thank you. 19

The other question I wanted to ask was how did the 20

renewables perform in this extreme weather? 21

MR. LEE XANTHAKOS [SCE&G]: I'm not aware of 22

any generation out of renewables during this 23

period, so it -- the event started at night, and it 24

was pretty much over by 10, so any solar panels 25


2/27/14


wouldn't have been getting any sunlight to generate 1

with, so they had no effect whatsoever on any of 2

the events -- neither helped or hurt. 3

VICE CHAIRMAN HALL: Okay. All right. 4


CHAIRMAN HAMILTON: Okay. Thank you, very 6

much. 7

We appreciate you gentlemen being here. I 8

think all of us rest assured that you are in charge 9

of the areas that you're in charge of. I think we 10

can take a great deal of satisfaction. And thank 11

you for your appearance. We stand adjourned. 12

[WHEREUPON, at 11:55 a.m., the 13

proceedings in the above-entitled matter 14

were adjourned.] 15

________________________________________ 16

17

18

19

20

21

22

23

24

25


2/27/14


C E R T I F I C A T E

I, Jo Elizabeth M. Wheat, CVR-CM-GNSC, do hereby

certify that the foregoing is, to the best of my skill and

ability, a true and correct transcript of all the proceedings

had in an Allowable Ex Parte Proceeding held before THE

PUBLIC SERVICE COMMISSION OF SOUTH CAROLINA in Columbia,

South Carolina, according to my verbatim record of same.

IN WITNESS WHEREOF, I have hereunto set my hand, on

this the 2nd day of March , 2014.

Hearings Reporter, PSC/SCNy commission Expires: Ja~avg 27; 2021.

SCE&G Allowable Ex Parte Communication Briefing

February 27, 2014

Controlled Load Shedding Event of January 7, 2014

2

Map | SCE&G Generation Map

• 6 Coal • 1 Simple Cycle Steam • 5 Combined Cycle Gas • 1 Nuclear • 1 Pumped Storage Hydro • 4 Run of River Hydro • 16 Simple Cycle Gas • 1 Biomass Co-generator

3

Hourly System Load Curves

4

1000

1500

2000

2500

3000

3500

4000

4500

5000

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24

MW

H

Hour Ending

1/5/2014

1/6/2014

1/7/2014

1/8/2014

1/9/2014

1/10/2014

1/11/2014

Gas Daily Indices ($/Dekatherm) 6-Jan 7-Jan 8-Jan

Southern Natural $ 4.31 $ 4.52 $ 4.56

Transco Zone 5 $ 10.78 $ 70.43 $ 26.29

Gas Daily Indices ($/Dekatherm)

6-Jan 7-Jan 8-Jan 9-Jan

Transco Zone 5 $ 10.78 $70.43

$26.29 $5.89

Operational Flow Orders (OFO)

5

Big Picture Timeline Jan 6 - Cold weather preps Jan 6 - OFOs limit gas availability Jan 6 - Advisory to interruptible customers Jan 6 - Urquhart 6/2 (242 MW) problems Jan 7 - Urquhart 5/1 (242 MW) shutdown @ 0205 Jan 7 - Williams (610 MW) shutdown @ 0621 Jan 7 - Issues experienced at other utilities cut purchases Jan 7 - Actions to preserve grid: - Request standby generator - Call on reserve sharing from other utilities

- Shutdown interruptible industrial customers - Voltage reduction - Controlled load shed

6

Why the Issue Close of Business Monday Jan 6 projections for Tuesday Jan 7: Load projection 4850 Megawatts Reserves 560 Megawatts

Actual loads higher due to colder temps Lost Urquhart & Williams 1094 Megawatts Emergency power from other utilities recalled

7

Summary We regret the inconvenience caused to our customers Total energy record set = 101,118 MWh Actions taken were to preserve the grid Shed load in controlled fashion Transmission & distribution systems functioned as expected

given the lost generation Plants can be bullet proofed against cold, but at a significant cost

8

Fossil Hydro Generation

9

Overview A cold snap occurred in S.C. during the week of Jan 6th

Temperatures were as low as 12 F in Columbia/Augusta and 18 F in Charleston with wind speeds up to 30 mph

The most significant lost generation issues were at Williams and Urquhart Stations

More information related to these specific locations is provided in the attached slides

This covers the time period from noon on January 6th thru noon on January 7th

10

Cold Weather Preparation The plants do cold weather checks when cold weather is

expected These checks are usually performed in November of each

year prior to Winter When extreme cold weather comes through the checks are

typically performed again The plants did the cold weather checks on the morning of

January 6th in anticipation of the cold weather coming that night

The plants were also instructed to avoid any maintenance or testing that could impact reliability of the units

11

Typical Cold Weather Checks Ensure external louvers are closed Check area heat pumps & space heaters Check heat tracing panels Have portable heaters on hand in the event they are needed If needed, bring in extra manpower to be on standby in the

event of problems Run peaking gas turbines on fuel oil for reliability checks

12

Gas Supply Issues Gas supply for all interruptible customers was curtailed on

January 3rd SCE&G has firm gas pipeline capacity in place for Urquhart

and Jasper but not enough for full load around the clock These gas supplies were being balanced to have enough gas

for full load during peak times We were also running some units on fuel oil as a part of the

balancing plan Although this can be complicated, we do it all the time

during cold weather and gas availability was not a factor in this event

13

General Timeline of Issues 12:08 PM/Jan 6th – Urq 6 tied on line w/ gas 01:15 PM/Jan 6th – Urq 3 in startup on gas 03:20 PM/Jan 6th – Unable to tie Urq 2 on line (Not

Weather Related) 10:30 PM/Jan 6th – Urq 6 tripped on fuel oil transfer (Not

Weather Related) 02:05 AM/Jan 7th – Urq 5/1 tripped on Gas 02:58 AM/Jan 7th – Urq 3 tied on line w/ Gas 06:21 AM/Jan 7th – Williams tripped

14

Urquhart 2 – Jan 6 3:20 PM – Urq 2 (66 MW) unable to tie on The cause was a generator breaker malfunction This was not weather related

15

Urquhart 6 – Jan 6th 10:30 PM – Urq 6 (176 MW) tripped on transfer to fuel oil Review indicated a leaking fuel purge valve – Mechanical

malfunction This was not weather related Valve was replaced with spare from Jasper Urq 6 returned to service on January 7th

16

Urquhart 5/1 – Jan 7th 2:05 AM – Urq 5/1 (242 MW) tripped while burning gas

The cause of the trip was a frozen steam drum pressure transmitter supply line

The line froze despite the presence of an automatic freeze protection system that was heating the line at the time of the trip

Complications with additional freezing and an industry issue with gas turbine fuel control inputs for cold weather delayed the restart

This gas control input issue affected approximately 50 units in the country on this day

Urq 5/1 was returned to service on January 8th

17

Urquhart 5 Drum Pressure Transmitter

18

Williams – Jan 7th 6:21 AM – Williams (610 MW) tripped

Review indicated a frozen pressure switch supply line as the cause

Automatic freeze protection (heat tracing) was present on the line

2 Heat trace circuits cover this supply line – 1 was working and 1 was not

The circuit that was not working had indication at the power supply source that the circuit was energized

There was an issue with the heat trace circuit along some part of the line below the insulation

This heat trace circuit has been repaired

19

Pressure Switch Enclosure Insulated & Heat Traced Pressure Sensing Line (1/2”)

Insulated & Heat Traced Drain Valves

20

Summary As discussed, the weather related issues resulted from an

equipment malfunction on automatic freeze protection systems

Similar issues occurred throughout the industry with transmitter freezing and also with the gas control inputs on large gas turbines

SCE&G continues to work on corrective actions and lessons learned as a result of this event

These items will be addressed to ensure we learn from this event and make necessary improvements

21

Transmission

22

Transmission Operations Center

Reliability Coordination

Transmission Operations

Balance, Interchange, and Scheduling

23

24

August 14, 2003

Recent USA Widespread Disturbances

September, 2011

24

SCE&G Balancing Area

Balancing Authority Area The collection of generation, transmission, and loads within the metered boundaries of the Balancing Authority. The Balancing Authority maintains load-resource balance within this area.

25

SCE&G Interconnections

SCE&G – 23 total tie lines

Southern – 2 ties with SOCO

Duke/Progress – 3 ties with CPLE

Santee Cooper – 13 ties with SC

Duke Carolinas – 4 ties with DUK

SEPA – 1 tie at Lake

Thurmond

PJM

26

Balancing Area

System Resources – Demand = Area Control Error (ACE)

Target: 0 ACE (±52MW)

27

Balancing

Machines Motors

Lights Heaters

Customer Load

As load comes in, the system becomes imbalanced and ACE becomes negative

28

Balancing

Machines Motors

Lights Heaters

Customer Load

System Control then adds Resources to Balance the ACE

Williams McMeekin

VCS Urquhart

System Purchases

Plus, we carry extra called Reserves

Reserves

29

VACAR Reserve Sharing Group

SCE&G 196 MW

Duke 497 MW Progress

377 MW

SCPSA 193 MW

Dominion 431 MW

For 2014 - Reserve Total 1694 MW’s

On January 7th – 3000MW extra

30

Day Ahead Plan – January 6, 3pm

System Purchase

McMeekin

VCS Cope

Reserves

4850MW Forecasted

Load Williams McMeekin

VCS Urq2/6

Jasper

Urq 1/5 Turbines

SCE&G Reserves: 560MW

VACAR Reserves: +3000

31

Day Ahead – January 6, Midnight

SCE&G Reserves: 358MW

Reserves

4900MW Forecasted

Load

Urq 6 - 160 MW Turbine Tripped (expected to come back)

System Purchase

McMeekin

VCS Cope

Williams McMeekin

VCS Reserves

Jasper

Urq 1/5 Turbines

32

January 7th 1:00am time frame Load tracking 375MW ahead of forecast Power not available to pump at Fairfield Pumped Storage (FFPS) Power not available on the market FFPS 1.1 foot below planned elevation

2:00 – 3:00am Lose 230MW when Urq 1/5 trips Using generation at FFPS heavily Interruptible Load Customers Curtailed (approx. 200 MW of load)

3:00 – 4:00am Call on 310MW Emergency Power from 2 companies

33

Timeline

6:00 – 7:00am Standby Generator Participants being generating (approx. 35 MW) At 6:21 – lose 610MW when Williams trips Call on 400 MW of Emergency Power from 2 companies Initiated voltage reduction through Distribution Dispatch Lose 49 MW when Urq 4 trips (back on line later) Conference call – there is no more energy available for emergency reserves

7:00 – 8:00am Lose 200MW of Emergency Power when it is recalled Direct 150MW of controlled Load Shed through Distribution Dispatch Receive 100 MW of Emergency Power from 1 company Direct Distribution Dispatch to hold load shed at 100MW

34

Timeline

8:00 – 9:00am Receive 300 MW of Emergency Power from 2 companies Lose 610MW of Emergency Power when it is recalled Lose 200MW of Emergency Power when it is recalled FFPS is at full load and low elevation Direct 200MW of additional controlled Load Shed through Distribution Dispatch Receive 200 MW Emergency Power from 1 company

9:00 – 10:00am Receive 500 MW Emergency Power from 2 companies Focus on generation reduction at FFPS Directed Distribution Dispatch to restored 100 MW of shed load

35

Timeline

10:00 - 11:00am Directed Distribution Dispatch to restore 50 MW of shed load Directed Distribution Dispatch to restore 50 MW of shed load Directed Distribution Dispatch to restore remaining 100 MW of shed load

11:00 – 12:00 Cancel voltage reduction Interruptible Customer curtailment ended

36

Timeline

5 yr. Historic Territorial Load Data

Winter

3000

3500

4000

4500

5000

5500

6000

2010 2011 2012 2013 2014(YTD)

Est.GrossPeak

Meg

awat

ts

2010 2011 2012 2013 2014 (YTD) Est. Gross PeakWinter 4718 4866 4397 3984 4853 5100

Recent Winter Peak Loads

37

Voltage Reduction/Load Shedding SCE&G Distribution System

38

Distribution System Prior to Load Shed

Distribution load on substation banks and feeders not experiencing overload situations

Distribution work schedule modified due to low temperatures

39

Preparation for Load Shed and Voltage Reduction

Annual review of distribution circuits Review customer circuits priority with regard to health,

safety, and welfare of communities served Coordination between System Control and Distribution

Dispatch

40

Category 1 –Circuits that do not contain a critical customer are the first circuits to be dropped from a distribution level during load shed events.

Breaker

School

Subdivision

Shopping Center

Subdivision

41

Category 2 – This is the next tier of distribution circuits to be shed once all of the Category 1’s have been dropped.

Breaker

School

Large Commercial Subdivision

Shopping Center

42

Category 3 – Critical customers are impacted at this level.

Breaker

Shopping Center

Hospital

Subdivision

Water Treatment Plant

43

-

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

450,000

500,000

550,000

600,000

650,000

# SC

E&G

Ele

ctric

Cus

tom

ers

(675

,000

)

Time sequence of Load Shed Events

SCE&G Customers Impacted by Load Shed Sequence January 7, 2014

44

January 7, 2014 06:52 Call from System Control to implement

Distribution Voltage Reduction

45

SCADA view to perform Voltage Reduction

46

January 7, 2014 07:35

Call from System Control to implement Distribution Load Shedding of 150 MW

47

SCADA Devices used to support Load Shed

48

07:58 Load Shed 16,628 Customers

49

08:27 Call from System Control to implement Distribution Load Shedding of 300 MW

50


51

Substation Breaker

52

Substation Bushing

Icicle

53


54

January 7, 2014 09:49

Call from System Control to implement Distribution Load Restoration of 100 MW

55

10:16 Block of Load Restored 36,903 Customers

56

10:27 System Control requests Restoration of All Load

57

10:50 – Remaining Outages following Load Shed Event 5,024 Customers

58

January 7, 2014 11:13 System Control requests Distribution Regulators set back

to normal (End of Voltage Reduction)

59

Questions

60

Date post:	17-Jan-2022
Category:	Documents
Upload:	others
View:	4 times
Download:	0 times

TRANSCRIPT OF ALLOWABLE EX PARTE BRIEFING

Documents