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DIRECT TESTIMONY OF 1
W. KELLER KISSAM 2
ON BEHALF OF 3
SOUTH CAROLINA ELECTRIC & GAS COMPANY 4
DOCKET NO. 2012-218-E 5
6
Q. PLEASE STATE YOUR FULL NAME, BUSINESS ADDRESS, AND 7
OCCUPATION. 8
A. My name is W. Keller Kissam and my business address is 220 9
Operation Way, Cayce, South Carolina. I am President of Retail 10
Operations of South Carolina Electric & Gas Company (the “Company” or 11
“SCE&G”). 12
Q. PLEASE STATE YOUR EDUCATIONAL BACKGROUND AND 13
EXPERIENCE. 14
A. I am a summa cum laude graduate of The Citadel, the Military 15
College of South Carolina. I joined SCANA Corporation in 1988 in the 16
New Utility Professional Program and held a number of industrial gas sales 17
and gas supply positions until 1994, when I was named Vice President of 18
South Carolina Pipeline Corporation with responsibilities for Contract 19
Administration and Gas Supply. Then in 1996, I was named Vice President 20
of Gas Operations of SCE&G, and in 2003, Vice President of Electric 21
2
Operations. In 2011, I assumed my current responsibilities as President of 1
Retail Operations. 2
Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THIS 3
COMMISSION? 4
A. Yes, I have testified before this Commission numerous times in 5
purchased gas adjustment proceedings, as well as storm response and other 6
operational matters. 7
Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? 8
A. The purpose of my testimony is to offer direct testimony with regard 9
to SCE&G’s electric transmission and distribution systems. I will focus 10
specifically on the actions taken by the Company to operate and maintain 11
its electric system in a safe and reliable manner. I will discuss the 12
Company’s proposals to place into current rates the reinstatement of 13
collections for the storm damage reserve and payment of storm damage 14
insurance premiums. I will also discuss SCE&G’s general customer 15
service offerings and their use by customers. I will discuss the Company’s 16
efforts to identify customers needing financial assistance as well as sources 17
administered or accessed by the Company to provide financial help to 18
customers in need. I will identify the customer growth experienced by the 19
Company since the last rate proceeding. And, finally, I will discuss 20
environmental remediation issues and explain the Company’s need for an 21
environmental recovery mechanism. 22
3
Q. WHAT IS THE MOST IMPORTANT FACTOR REGARDING THE 1
COMPANY’S EFFORTS TO PROVIDE SAFE AND RELIABLE 2
ELECTRIC SERVICE? 3
A. Safety is the most important aspect of the Company’s mission. 4
Reflective of the clear focus that the Company devotes to its safety mission 5
is that SCE&G transmission and distribution operations has received the 6
top safety award given by the Southeastern Electric Exchange (“SEE”)for 7
three out of the last four years and the last two consecutive years. The 8
number one element that allows the Company to receive these awards and 9
that comprises its efforts to provide safe reliable service is the Company’s 10
dedicated employees. All of our power line workers complete a rigorous 11
four-year apprenticeship, where they are taught to safely and effectively 12
perform their duties. This training is critical because the Bureau of Labor 13
Statistics identifies the position of power line worker as one of the ten most 14
dangerous jobs in the United States. SCE&G’s electrical workers care for 15
each other and pass this concern onto each customer every day as they 16
provide safe and reliable electric service. Table 1 sets forth the Accident 17
Frequency Ratio results based upon Occupational Safety and Health 18
Administration reported incidents per 200,000 people hours that 19
demonstrate SCE&G’s commitment to being an industry leader for safety. 20
4
Table 1 1
SCE&G Electric Operations Accident Frequency Ratio 2
2000-2011 3
(Source: Company Data) 4
5
Q. WHAT OTHER FACTORS DOES THE COMPANY INTEGRATE 6
INTO ITS PROVISION OF SAFE AND RELIABLE ELECTRIC 7
SERVICE TO CUSTOMERS? 8
A. In maintaining an electric system with 3,674 miles of transmission 9
lines and 18,108 miles of distribution lines, in addition to numerous 10
additional infrastructure assets supporting that system, the Company 11
constantly performs operations, maintenance, and construction activities, 12
some required by federal law and regulations, and others necessary to 13
0
SEE& G Elecrric Opemtions ranked ¹1 among 18 reporting companies xxithin SourheasremEiecrric Exchange for3 out of the lasr 4 years.
5
provide safe and reliable electric service that our customers both expect and 1
rely upon as essential in their lives. 2
Q. WHAT IS THE IMPACT TO THE COMPANY FROM FEDERAL 3
REGULATIONS REGARDING ELECTRIC RELIABILITY 4
STANDARDS? 5
A. In 2003, 55 million consumers lost electric service for a sustained 6
period as a result of vegetation-caused outages that cascaded into a major 7
impact to the national transmission grid in the northeastern United States 8
and Canada. In response to these outages, Congress included in the Energy 9
Policy Act of 2005 the authority for the Federal Energy Regulatory 10
Commission (“FERC”) to issue mandatory electric reliability standards and 11
the North American Electric Reliability Council (“NERC”) was designated 12
as the statutory Electric Reliability Organization (“ERO”) authorized to 13
enforce these standards. The ERO has authority not only to enforce the 14
reliability standards, but also to levy fines in the amount of up to $1 million 15
per day per event for non-compliance. 16
These standards apply to all aspects of planning, operating, 17
maintaining, and constructing the Company’s transmission assets, including 18
tree trimming and associated vegetation management, personnel training, 19
inspection and repair of facilities, and protection of both systems and 20
facilities. A major component of these standards involves cyber-security 21
measures to prevent disruption of transmission system operations by 22
6
malicious computer programs. Physical security of control centers are yet 1
another critical requirement as well. The Company has established 2
procedures to comply with each of these standards. 3
A final component of these standards requires periodic audits of the 4
Company’s compliance programs and corresponding data and record-5
keeping. The Company must prepare for this reporting; therefore, 6
personnel and systems must focus daily in preparation for both self-audits, 7
spot audits, self-reporting incidents, and formal audits. Since inception of 8
these standards, the Company has experienced two formal audits with the 9
results being “no findings.” These results would have not been possible 10
absent Commission Order Nos. 2009-87, 2009-845, and 2011-126, which 11
enabled the Company to achieve its positive results by allowing for the 12
funding of certain vegetation management activities from the established 13
Storm Damage Reserve. With the authorization granted by the 14
Commission, SCE&G’s Transmission Vegetation Management Program 15
(“TVMP”) not only has resulted in full compliance with stringent, 16
prescriptive NERC-mandated regulations for vegetation management, but 17
also has contributed to improved reliability of the Company’s electric 18
system by increasing the system’s tolerance to weather related events. 19
Implementation of the TVMP also has significantly reduced the problems 20
posed by “danger trees,” which are trees not located in the Company’s 21
actual right of way, but are near or have grown into the Company’s rights 22
7
of way and may have been impacted by drought, disease, or infestation and, 1
as such, represent a certain threat to reliable electric service. 2
Q. HOW HAVE THESE FEDERAL REGULATIONS IMPACTED 3
PLANNING, CONSTRUCTION, AND MAINTENANCE 4
FUNCTIONS? 5
A. The federal regulations, applied through the NERC Planning 6
Standards and implemented by SCE&G’s Internal Planning Criteria, 7
require that SCE&G’s electric transmission system must withstand specific 8
events on the electrical system while continuing to serve firm load 9
requirements and provide firm transmission services. The system must be 10
continually modeled and analyzed to ensure reliability of the Company’s 11
transmission system as well its interconnections with neighboring utilities. 12
Thus, the SCE&G transmission system must be designed so that, during 13
certain contingencies, only short-term overloads, low voltages, and local 14
load loss will occur and the national electric grid will not be adversely 15
impacted. These contingencies include, but are not limited to, loss of any 16
generator; loss of electrical bus operating at voltage greater than 115 17
kilovolts (“kV”); loss of entire generating capacity at any one plant; loss of 18
all circuits on a common structure; loss of generating unit simultaneously 19
with the loss of a single transmission line; loss of all components associated 20
with breaker failure; and loss of any generator, transmission circuit, or 21
transmission transformer followed by manual system adjustments, followed 22
8
by the loss of another generator, transmission circuit, or transmission 1
transformer. SCE&G designs and maintains its system to properly respond 2
to these contingencies so that, after appropriate switching and dispatching 3
events, all non-radial loads can again be served with reasonable voltages 4
and all facilities are operating within acceptable limits. 5
However, as a result of such planning criteria, the Company is 6
continually required to make large capital investments not only for the 7
purpose of expanding capacity, but also to maintain the present system’s 8
operating integrity and comply with federal regulations. In fact, during the 9
2011 test period (the “Test Year”) within this docket, the largest capital 10
investment for transmission projects were the Denny Terrace-Pineland 230 11
kV line and the expansion of the Graniteville Substation, both of which 12
were projects for the sole purpose of meeting the required reliability 13
standards of SCE&G’s transmission system and its interconnection with 14
neighboring utilities. These upgrades do not expand the Company’s 15
capacity. Rather, these upgrades are implemented to comply with federal 16
regulatory requirements directed toward maintaining the overall integrity of 17
the national electric grid by enhancing the Company’s ties to and 18
connections with neighboring electric utilities. Nonetheless, although there 19
is no expanded capacity, both customers and the Company receive a benefit 20
through the existence of a more reliable and robust transmission system 21
9
operated by SCE&G as well as access to a national electric transmission 1
system that is enhanced by these same upgrades. 2
Maintenance of the Company’s infrastructure is also a critical 3
component of reliability standards. Substation components must be 4
constantly inspected and activated for proper operation. This includes 5
maintenance of switches, oil testing of transformers, setting and trip testing 6
of relays, breaker maintenance, battery testing and maintenance, and 7
performance of other inspections required to ensure reliability. If such 8
maintenance indicates problems beyond what preventative maintenance can 9
correct, total replacement of components is required. Trending of 10
equipment operating temperatures through the use of thermal infrared 11
detection, as well as abnormal equipment readings, are also important 12
maintenance data allowing the Company to identify and address 13
problematic issues as efficiently and effectively as possible. 14
Transmission lines must be inspected and maintained as well. 15
Annual flight patrols allow for efficient observation of the Company’s 16
aging infrastructure. Pole replacement, brace replacement, and hardware 17
change-outs are a part of daily follow-up from such patrols. NERC 18
recently recommended that all transmission entities assess their structures 19
and lines with LiDAR (“Light Detection and Ranging”) to confirm design 20
clearances on all transmission line infrastructure. The Company has 21
implemented this recommendation, which involves an aerial survey of its 22
10
transmission line infrastructure by a LiDAR-equipped helicopter. The 1
LiDAR technology involves use of a laser, typically installed in a pod 2
underneath the helicopter, by which the existing design clearances are 3
determined with a very high degree of accuracy. The Company then 4
reviews and applies this data to ensure compliance with federal regulations 5
as well as the Company’s internal requirements. 6
Q. WHAT OTHER FEDERAL OR NATIONAL STANDARDS MUST 7
THE COMPANY APPLY AS PART OF ITS ONGOING 8
MAINTENANCE ACTIVITIES? 9
A. As I indicated previously, NERC standards also require each utility 10
to have a TVMP. This prescriptive planning document must detail every 11
aspect of transmission right of way maintenance for the Company. 12
Associated record-keeping systems are also necessary to document that 13
appropriate maintenance activities have been performed. Although 14
prescribed by NERC and, thus, directed toward maintenance and protection 15
of the national electric grid, vegetation management is crucial to the 16
Company’s mission and its maintenance plan for both transmission and 17
distribution lines. 18
11
Q. WHY IS VEGETATION MANAGEMENT SUCH A CRITICAL 1
COMPONENT OF SCE&G’S MAINTENANCE PLAN TO DELIVER 2
SAFE AND RELIABLE SERVICE? 3
A. Tree trimming and vegetation management programs are 4
maintenance activities that are critical to reliable utility operations and the 5
rapid restoration of electric utility service after storms or other events. 6
Post-storm reviews and investigations regarding system outages caused by 7
heavy winds, snow, thunderstorms, tornadoes, hurricanes, and especially 8
ice have consistently resulted in recommendations to develop more 9
comprehensive and focused vegetation management plans to improve 10
reliability and customer service. As mentioned above, it is now mandatory 11
under the ERO standards that utilities adopt and carry out a documented 12
vegetation management plan. Failure to execute the plan as adopted 13
subjects the utility to self-reporting requirements and the potentially severe 14
monetary penalties discussed above. 15
Q. PLEASE EXPLAIN HOW VEGETATION ISSUES IMPACT THE 16
COMPANY’S DISTRIBUTION LINES. 17
A. Although the federal requirements apply only to transmission line 18
rights of way, the Company has long recognized that the need for and 19
benefits of vegetation management apply equally to the Company’s 20
distribution lines and rights of way. In 2006, SCE&G developed and 21
implemented a pilot program, similar to the TVMP, for its distribution 22
12
lines: the Distribution Vegetation Management Program (“DVMP”). The 1
DVMP was designed to (i) assign each circuit on the distribution system a 2
reliability index; (ii) identify each circuit’s most recent tree trimming and 3
vegetation management cycle; (iii) identify critical customers (e.g., 4
hospitals) using power on each circuit; and (iv) discuss vegetation 5
management practices with SCE&G’s local operating managers responsible 6
for overseeing each circuit. The DVMP also included a five-year 7
vegetation management cycle and vegetation trimming guidelines that 8
required trimming to a minimum clearance of 20 feet above, and a 9
minimum clearance of ten feet below and to either side of a distribution 10
line. Tree-trimming contractors bid on circuit work by units of cost per 11
mile or cost per circuit. 12
Q. HOW DO THE TVMP AND DVMP CONTRIBUTE TO THE 13
SAFETY, RELIABILITY, AND PROTECTION OF THE 14
COMPANY’S ASSETS? 15
A. SCE&G’s expanded efforts in tree trimming and vegetation 16
management have provided tremendous reliability improvements for our 17
customers while reducing the damage done to our system by storms. 18
Vegetation control and tree trimming contribute significantly to safety, 19
reliability, and asset protection. 20
Safety – Downed power lines are dangerous to the public for 21
obvious reasons. In addition, storm damage restoration is the most 22
13
dangerous job required of SCE&G linemen. SCE&G personnel have to 1
work long hours often at night in bad weather to restore circuits damaged 2
by storms. Effective tree trimming reduces the risk, danger, and difficulty 3
of storm damage restoration. Even in non-storm conditions, it is more 4
dangerous for crews to work around power lines where access and sight-5
lines are obscured by vegetation than around lines that have been subject to 6
proper tree trimming and vegetation control. 7
Reliability – Effective tree trimming has a major impact on system 8
reliability. Customers rely on electricity to keep their families safe and 9
comfortable. Effective tree trimming reduces the number and duration of 10
storm related outages which allows our customers to go about their lives 11
with less disruption and uncertainty and with a much higher level of safety 12
and security. 13
Asset Protection – Tree trimming protects transmission and 14
distribution lines from storm damage, which is expensive to restore and 15
results in significant additional capital costs added to our system. In 16
addition, when lines are lost, breakers trip off and the resulting disruption in 17
load places stress on transformers, switch gear, and other assets. This 18
reduces the useful lives of these assets and increases maintenance costs. 19
Q. WHAT RESULTS HAVE BEEN ACHIEVED? 20
A. Due to the foresight of this Commission as reflected in previously 21
referenced orders, the Company not only has complied with federally-22
14
mandated regulations, but also has achieved unprecedented improvements 1
in customer reliability and system efficiency. The key component in the 2
Company’s vegetation management plan is, however, implementation of 3
and adherence to a five-year distribution trimming cycle. 4
The Company’s success in this regard is illustrated by the mileage 5
that the Company has efficiently and promptly cleared. As shown in Table 6
2, the Company cleared almost 500 miles of transmission line rights of way 7
in 2011 and, as reflected in the slope of the line, made steady and 8
systematic progress throughout the year. 9
Table 2 10
Transmission Line Right-of-Way Mileage Cleared in 2011 11
(Source: Company Data) 12
13
496.52
0
100
200
300
400
500
600
2011 Transmission Line Clearing Plan
Miles
15
Table 3 reflects the Company’s progress in clearing danger trees 1
from transmission line rights of way during 2011. The Company makes a 2
concerted effort to remove these trees from the transmission line rights of 3
way in order to improve reliability and to comply with Federal regulations. 4
The reason that Table 3 reflects peaks of activity at different times during 5
the year, as opposed to a steady level of activity like that reflected in Table 6
2, is that the Company identifies and eliminates danger trees in large part 7
by conducting aerial patrols of the transmission line rights of way during 8
the year, then directing crews to the problem areas to remove the trees. 9
Thus, the peaks of activity reflected in Table 3 result from aerial patrols 10
conducted during that month. 11
16
Table 3 1
Danger Trees Cleared from Transmission Line Rights of Way by Month 2
(Source: Company Data) 3
4
Charts, however, do not fully depict the extensive nature of the 5
Company’s efforts in clearing the transmission line rights of way. The 6
thoroughness of these efforts is evidenced by the following photo sets of 7
two different transmission line segments taken from approximately the 8
same vantage point before and after the clearing was performed. 9
17
Photo Set 1 1
Summerville –Williams 230 kV 2
(Source: Company Photographs) 3
4
Before After 5
18
Photo Set 2 1
Church Creek - Faber Place 230/115 kV 2
(Source: Company Photographs) 3
4 Before After 5
The Company’s success in this regard is not limited to vegetation 6
management on the transmission lines alone. Table 4 below reflects that 7
the Company cleared almost 2,500 miles of distribution line rights of way 8
in 2011 and, like the results shown in Table 1 with respect to transmission 9
line rights of way, made steady and systematic progress throughout the 10
year. 11
19
Table 4 1
Distribution Line Right of Way Mileage Cleared in 2011 2
(Source: Company Data) 3
4 5
The Company’s existing vegetation management plan includes 6
making efficient use of resources by transitioning from hourly work for 7
clearing vegetation to having contractors submit bids to perform the work 8
based on cost per circuit or cost per mile. The Company has also 9
consolidated bids for transmission and distribution circuits located in the 10
same general area reducing mobilization of crews for multiple visits. In 11
addition, in specific areas, the Company is utilizing specialty herbicides to 12
eliminate invasive species and actually promote native growth of grasses 13
and forbs. Photo 3A, below, depicts a typical overgrowth of these grasses 14
2460.15
0
500
1000
1500
2000
2500
3000
2011 Distribution Line Clearing Plan
Mile
s
20
and forbs prior to vegetation clearing and application of any specialized 1
herbicide treatment program. 2
Photo 3A 3
Before Clearing and Treatment 4
(Source: Company Photograph) 5
6
The positive impact of these herbicide applications is reflected in 7
Photo 3B, below, which reflects the results of clearing and of selectively 8
using herbicides to address problem species without adversely impacting 9
non-invasive grasses and forbs. 10
Wi" IIt .
~ I't
~,
r'4$
»
Ig7.+P" r
,. i'~t'
21
Photo 3B 1
After Clearing and Treatment 2
(Source: Company Photograph) 3
4
As part of the vegetation management plan, SCE&G also has 5
developed specifications reviewed by tree care professionals and 6
incorporated in ANSI 300 standards that promote the health of trees by 7
training them with prudent and structured cuts to grow away from power 8
lines. Examples of trimming to these careful specifications are represented 9
in the pictures below. Each picture set reflects the before-and-after results 10
of the Company’s careful application of these prudent and structured cuts to 11
rights of way that experience significant vegetation encroachments due to 12
the vigorous growing season across the Company’s service area. 13
I
,4'%.
'r
//cr k
q'/
c
. r
22
Photo Set 4 1
Wando Circuit 95122 2
(Source: Company Photographs) 3
4 Before After 5
23
Photo Set 5 1
Riverland Terrace Circuit 11532 2
(Source: Company Photographs) 3
4 Before After 5
Q. HOW HAS IMPLEMENTATION OF THE COMPANY’S 6
VEGETATION MANAGEMENT PLANS IMPROVED ELECTRIC 7
SERVICE RELIABILITY TO ITS CUSTOMERS? 8
A. The Company’s System Average Interruption Duration Index 9
(“SAIDI”), which provides an index of the annual average minutes of 10
outage duration per customer, has improved by 20% in the last five years as 11
compared to the previous five years. Table 5 depicts the Company’s SAIDI 12
over the last five years compared to the previous five years. 13
24
Table 5 1
Five-year SAIDI Average Comparison 2
Years 2002-2006 and Years 2007-2011 3
(Source: Company Data) 4
5
The success of the Company’s vegetation management plans is 6
further reflected in an analysis of the Company’s experience during each 7
year from 2008 through the Test Year. The Company’s continuing 8
improvement in its performance is reflected in Table 6, which demonstrates 9
that vegetation caused outages have declined substantially during this time 10
period. 11
146117
0
20
40
60
80
100
120
140
160
2002 ‐ 2006 Avg. 2007 ‐ 2011 Avg.
Outage M
inutes
SAIDI Improvement5 year average
25
Table 6 1
Vegetation Caused Outages 2
Years 2008-2011 3
(Source: Company Data) 4
5
6
The Company’s improvement with respect to vegetation issues is 7
further demonstrated by Table 7, which shows that the number of customer 8
service minutes lost annually due to vegetation caused outages has declined 9
substantially during the 2008-2011 time period. 10
26
Table 7 1
Customer Service Minutes Lost Due to Vegetation Events 2
Years 2008-2011 3
(Source: Company Data) 4
5
6
In sum, the Company continues to refine and improve the reliability 7
of its electric service. 8
27
Q. IN VIEW OF THE SUCCESS OF THE VEGETATION 1
MANAGEMENT PLANS, ARE THE COMPANY’S PROPOSALS TO 2
PLACE INTO CURRENT RATES THE REINSTATEMENT OF 3
COLLECTIONS FOR THE STORM DAMAGE RESERVE AND 4
PAYMENT OF STORM DAMAGE INSURANCE PREMIUMS 5
REASONABLE AND NECESSARY? 6
A. Yes. As effective as the vegetation management plans are in 7
reducing and minimizing the damage from many storms and adverse 8
weather events, they cannot eliminate all damage. Moreover, the impact of 9
major storms such as the destruction wrought by Hurricane Hugo in 1989 10
could be catastrophic to SCE&G’s facilities. Company Witness Harris has 11
performed a Storm Loss Analysis concluding that if a major hurricane 12
makes landfall on the southern or central South Carolina coast, the funds 13
that presently are available in the Storm Damage Reserve as of July 31, 14
2012 will be quickly exhausted. Witness Harris also states that the greatest 15
potential for damage to the Company is a hurricane making landfall near 16
Beaufort with a northern arm extending into the Charleston, Orangeburg, 17
and Columbia areas. Because these locations include the major 18
metropolitan areas within the Company’s service area, a hurricane like that 19
described by Witness Harris would have a major impact on the Company’s 20
assets. To provide a measure of protection against any rate increases that 21
necessarily would result from service restoration efforts carried out in 22
28
response to any such weather event, reinstatement of the annual collections 1
for the Storm Damage Reserve in the amount of $6.1 million for the 2
purpose of increasing the reserve toward the authorized level of $100 3
million is reasonable and necessary. 4
Witness Harris also notes that a Category 4 hurricane could cause 5
damages in excess of $100 million, which is the ceiling for coverage by the 6
Storm Damage Reserve even when fully collected, which is not the case 7
today. To limit the immediate and difficult rate impact to customers that 8
would result from requiring the Company to seek recovery of such 9
expenses through rates after the amounts for restoring electric service are 10
incurred, an insurance policy that insures against losses in excess of $100 11
million, but not more than $170 million, under the terms described by 12
Witness Harris, is reasonable and necessary. 13
Q. HOW RELIABLE WAS SCE&G’S SERVICE TO ITS ELECTRIC 14
CUSTOMERS DURING 2011? 15
A. In 2011, SCE&G’s SAIDI was 115. In terms of system reliability, 16
this means that on average throughout 2011, SCE&G’s system was 17
available to meet the electric needs of its customers 99.98% of the time. 18
Q. WHAT OTHER MAINTENANCE ACTIVITIES ARE IMPORTANT 19
FOR RELIABILITY OF THE COMPANY’S ELECTRIC SERVICE? 20
A. The Company constantly models its distribution system. Although 21
economic growth has been slowed recently, economic development 22
29
announcements, coupled with demographic shifts, require new distribution 1
breakers, wires, and poles to be installed. In addition, existing 2
infrastructure must be inspected and maintained. For example, SCE&G has 3
almost 500,000 poles and transformers that are critical to reliability. A 4
circuit inspection program, on an eight-year cycle, coupled with correction 5
of any findings on an annual basis, is integral to continued operations. 6
Q. WHAT STEPS HAS THE COMPANY TAKEN TO MINIMIZE THE 7
ADVERSE IMPACT TO CUSTOMERS FROM OUTAGES? 8
A. In addition to the regular maintenance and vegetation management 9
issues described above, which constitute the most effective methods of 10
minimizing the impact of outages by reducing or eliminating causes of 11
those outages, the Company has installed Supervisory Control and Data 12
Acquisition (“SCADA”) switches throughout its service territory. These 13
switches allow for the remote operation and isolation of SCE&G’s 14
electrical system during outages. This system, comprised of 779 SCADA 15
devices, is managed 24 hours a day/seven days a week by trained 16
dispatchers. These switches enhance the reliability and availability of the 17
electrical system as well as the safety of the Company’s employees and of 18
the public. 19
The SCADA switches assist in minimizing the impact of an outage 20
by isolating any disruption to a specific part of a line segment for a circuit. 21
Once an outage is detected, the dispatcher will activate, or open, the nearest 22
30
SCADA switches on either side of the location of the outage, which has the 1
effect of isolating the area with the outage from the remaining elements of 2
the electric circuit impacted by the outage. The electric system is then 3
reenergized from the nearest substations to the location of the two opened 4
SCADA switches, which restores electric service to customers who are not 5
within the isolated segment of the line. Once the circuit has been 6
sectionalized and the problem on the line isolated, crews are quickly 7
dispatched to the specific area in which the outage event occurred in order 8
to safely and efficiently restore electrical service. Employee and customer 9
safety is enhanced through this process by isolating the disruption from the 10
energized segments of the Company’s electric system as well as by 11
ensuring that the impact of the electric outage is limited. 12
Photo Set 6 reflects the installation of SCADA switches on a 13
distribution circuit. In this photograph, the SCADA switches—indicated 14
by the yellow arrows—are open, which is shown by the device arm 15
extended to the left in the photograph. When the switch is open, the line is 16
not connected and, thus, the parts of the circuit on either side of the switch 17
are isolated from one another. The SCADA switch shown in the small 18
photo inset at the bottom left of the photograph is closed, indicating 19
electrical current is flowing through the device. 20
31
Photo Set 6 1
SCADA Switches Located on Distribution Pole 2
(Source: Company Photograph) 3
4
The actual operation of the switches is shown in Diagram 1 and 5
Diagram 2, below. In Diagram 1, a fault has occurred downstream or 6
below the SCADA switch # 54321. Accordingly, an open point has already 7
been established by the dispatcher between Substation A and Substation B, 8
and customers served from Substation B are not impacted by the fault. 9
32
Diagram 1 1
SCADA Switch Normal Open Position 2
(Source: Company) 3
4
Next, the dispatcher opens the SCADA switch #54321 immediately 5
upstream of the fault, which isolates the outage event from the customers 6
between the switch and Substation A and, as reflected by the green line 7
shown in Diagram 2, has the effect of completely deactivating electric 8
power in the isolated segment of the line. The circuit breaker in Substation 9
A then closes and the electric line is reenergized from Substation A to the 10
SCADA switch #54321, which restores electric service to customers 11
located in that segment of the line. The time period from detection of the 12
fault to completion of the switching process and restoration of electric 13
Automatic Sectionaiizing SwitchVoltage and Current are monitored at switch
Substation A
SCADA GS ¹54321
ault
Fault detected downstream of switch
Substation 6
33
service to a majority of affected customers typically is only a few minutes. 1
The completion of this process is demonstrated in Diagram 2. 2
Diagram 2 3
Second SCADA Switch Opened 4
Isolation of Fault Initiated 5
(Source: Company) 6
7
In addition to benefitting customers by minimizing outage impacts, 8
these switches and devices also provide communication to important 9
systems such as the Outage Management System (“OMS”) and the 10
Customer Information System (“CIS”), both of which are directly linked to 11
the Company’s Geographic Information System (“GIS”). The integration 12
of these systems affords the following benefits to the Company and its 13
customers: (1) Dispatchers receive both a graphic and empirical view of 14
Automatic Sectionaiizing Switch
Voltage and Current are monitored at switch
SCADA GS ¹54321
Substation A
Breaker closes
Substation B
34
the conditions of the SCE&G electrical system; (2) Line crews receive the 1
benefit of proactive data regarding the location of events causing outages 2
prior to arriving on the scene; (3) Customer representatives can 3
communicate directly with customers regarding the cause of outage, 4
location of crews, and estimated time of restoration; and (4) Customers can 5
also view outage maps and real-time outages across the system or even in 6
their own neighborhood. These systems are vital to the communication 7
with all stakeholders involved in this essential restoration process. 8
Q. WHAT OTHER STEPS HAS THE COMPANY TAKEN TO REDUCE 9
THE DISRUPTION AND UNCERTAINTY RELATED TO SERVICE 10
INTERRUPTIONS? 11
A. SCE&G offers its customers an Estimated Time of Outage 12
Restoration (“ETOR”) to reduce the uncertainty related to service 13
interruptions. The ETOR system allows customers to phone in during an 14
outage and receive automated real-time updates of the estimated time when 15
service will be restored to them. This is in addition to web-based outage 16
information, including current outage maps, that is available at 17
www.sceg.com/storm. The benefit to customers of this system, including 18
those actually experiencing a temporary outage, is that the maps and other 19
information are available to them through mobile and wireless internet 20
capable devices. 21
35
Q. HOW DOES THE ETOR SYSTEM WORK? 1
A. The system, which was internally developed by SCE&G, is fully 2
automated. Crews in the field communicate information concerning the 3
repairs required to restore service. The system then estimates the time until 4
service restoration based on the caller’s address and the average time to 5
complete the repairs. The system has been extremely well received by 6
customers. The accuracy of estimated restoration times is reviewed 7
monthly based on the actual time of repairs experienced by the Company. 8
The system is updated periodically to improve the accuracy of the 9
estimation process. 10
Q. HOW ARE THE ESTIMATED RESPONSE TIMES 11
COMMUNICATED TO CUSTOMERS? 12
A. Customers experiencing an outage at their home may access the 13
Company’s estimated response time through the Company’s automated 14
telephone system, a mobile phone, a wireless computer, or a wired 15
computer if the customer is away from their home during the outage. 16
Q. PLEASE PROVIDE INFORMATION ABOUT SCE&G’S GENERAL 17
CUSTOMER SERVICE OFFERINGS. 18
A. Contact centers, business offices, and websites are the key to 19
effective customer service because most of SCE&G’s customers interact 20
with the Company through one or more of these mediums. Over the past 21
several years, the Company has put a great deal of effort into improving its 22
36
contact center systems and making its website more functional and 1
accessible to its customers. Customers now have the convenience of using 2
credit and debit cards to make payments through the Company’s website, 3
the Interactive Voice Response System (“IVR”), or in person at SCE&G 4
business offices. 5
Through SCE&G’s website, residential and commercial customers 6
can access account information and make service requests. These 7
customers also have the option of setting up a “paperless” account where all 8
billing and payment transactions can be handled real-time via the internet. 9
In 2011, SCE&G’s website was ranked 10th out of 100 utilities nationwide 10
by E Source, an independent utility research firm. Rankings are based on 11
ease of use, functionality, and performance. 12
Customer usage of SCE&G’s IVR continues to increase giving 13
customers quicker access to the features they use most often. Currently, 14
over 37% of our transactions are handled through IVR versus the industry 15
average of 20%. The number of customer calls serviced by IVR has 16
increased by 16% since 2007. 17
SCE&G understands that during outages customers want to report 18
the outages and, in response, receive an estimated time of restoration and 19
outage updates through channels they prefer. Customers have the ability to 20
report outages directly into the outage management system through IVR, 21
the internet, their mobile device, or through text messaging, as well as 22
37
reporting through a customer representative if they prefer. Since 1
implementation of this service in April 2011, over 5,000 customers have 2
registered for texting outage reports and receiving outage status updates. 3
As part of this service, the Company makes available an interactive 4
outage map on its website, which provides customers with geographic 5
information regarding the status of outages directly from the outage 6
management systems and electric dispatching. Customers will be able to 7
view the outage map from their mobile device or tablet by the end of this 8
year. Presently, the broadcast media use this system during news 9
broadcasts, especially during times of severe weather, to obtain prompt 10
information regarding the status and extent of outages across the 11
Company’s service area. In 2011, SCE&G was the winner in the Customer 12
Service and Billing category of the SEE Industry Excellence Awards for 13
the ‘Interactive Electric Outage Map.’ 14
The value of the Company’s website and these customer-oriented 15
services is shown in the fact that the number of residential online accounts 16
has grown by 58% since 2007, and 47.1% of residential accounts are now 17
online as of the end of the Test Year. In fact, 27% of the Company’s 18
residential accounts are now paperless, reflecting an acceptance rate that is 19
more than double the national adoption rate of 12%. 20
38
Q. WHAT RECOGNITION HAS SCE&G’S CUSTOMER SERVICE 1
RECEIVED? 2
A. Most recently, for the period July 2011 through May 2012, SCE&G 3
tied for 3rd place in the South Region of the Electric Utility Residential 4
Customer Satisfaction Study conducted by J.D. Power and Associates. The 5
Company was ranked 2nd among large electric utilities in the South Region 6
in the 2012 Business Customer Satisfaction Study conducted by J.D. Power 7
and Associates. 8
Q. WHAT HAS SCE&G DONE TO HELP ITS CUSTOMERS MANAGE 9
THEIR ENERGY USE AND MONTHLY BILLS? 10
A. SCE&G has energy teams focused on helping customers manage 11
their energy consumption. Since forming in 2008, the teams have 12
conducted more than 4,700 Home Energy Checkups. A member of the 13
SCE&G Energy Team visually inspects windows, doors, caulking, weather 14
stripping, insulation levels, appliances, water heaters, and heating and 15
cooling systems, then assesses the home’s energy efficiency, and 16
recommends steps for improving the home’s overall energy usage. 17
In late 2010, SCE&G began implementing a comprehensive 18
portfolio of energy efficiency programs for its residential and 19
commercial/industrial electric customers. In the first year after these 20
programs were launched, the Company estimates that the programs 21
39
collectively helped reduce consumption of electricity by about 57,000 1
megawatt hours–roughly equivalent to the monthly power consumption of 2
about 48,000 homes. 3
Since October 2010, members of our Energy Efficiency/Demand 4
Side Management team have made over 230 formal presentations to state-5
wide associations, non-profits, builder/contractor groups, neighborhood 6
associations, senior citizens, and business-related organizations, just to 7
name a few. 8
Q. WHAT TYPES OF ASSISTANCE CAN CUSTOMERS RECEIVE 9
FROM SCE&G? 10
A. For customers having immediate difficulty paying a bill, customer 11
service representatives can offer short-term arrangements to assist 12
customers in extending the time in which to make their payments. Where 13
more time is required, the Company offers customers the ability to pay an 14
outstanding balance through a deferred payment plan. When customers 15
have medical conditions requiring uninterrupted electric service, the 16
Company offers a medical certificate program ensuring continued service 17
even when there are payment defaults. 18
Q. WHAT SUCCESS HAS THE COMPANY EXPERIENCED IN 19
THESE EFFORTS TO WORK WITH ITS CUSTOMERS? 20
A. In the month of December 2011 alone, the Company extended 21
special assistance to a total of approximately 63,000 customers. In that 22
40
month, approximately 89,000 customers were receiving assistance in 1
managing their energy bills through the Budget Billing Program. 2
Q. PLEASE DESCRIBE WHAT OTHER RESOURCES YOU HAVE 3
AVAILABLE FOR CUSTOMERS. 4
A. SCE&G has a strong Customer Assistance Program, administered 5
through representatives in the customer service department specifically 6
trained and dedicated to identifying and working with those customers who 7
need special assistance. The Company also maintains a third-party 8
notification program, which allows customers to provide the name and 9
address of someone to be notified by mail, along with the customer, when 10
an account becomes delinquent. Once customers in need are identified, 11
customer assistance specialists work with them to identify appropriate 12
sources of help. In 2011, through the combined efforts of SCE&G’s 13
Customer Assistance Program and its more than 150 agency partners, 14
SCE&G’s customers received approximately $9.1 million in direct energy 15
assistance. 16
In addition to identifying customers needing assistance, the 17
Company also facilitates sources of assistance. The Company supports the 18
United Way, both through corporate and individual financial donations as 19
well as through Company personnel who donate their time and talents by 20
participating in various United Way projects designed to assist the needy in 21
the community. The Customer Assistance area designed and implemented 22
41
WebPledge, an online tool that allows community action agencies to 1
quickly and easily pledge a specific amount to a household in need of 2
energy assistance. In 2008, SCE&G’s WebPledge was awarded the SEE 3
“Industry Excellence Award” for Customer Service and Billing. 4
The Company makes available customer assistance from several 5
different sources. The Customer Assistance area administers “The Good 6
Neighbor Fund,” by which employees contribute funds and make referrals. 7
In 2011, this fund provided 408 families with a total of $221,868 in funds, 8
an average of $543 per family, and also provided holiday food baskets to 9
600 families in South Carolina, including holiday gifts for each child in 10
these families that is 14 and under. The Low Income Home Energy 11
Assistance Program (“LIHEAP”) is a U.S. Department of Energy program 12
that assists low income households in meeting immediate home energy 13
needs. Local community action agencies distribute LIHEAP funds and 14
SCE&G coordinates with these agencies to credit the funds to customers. 15
Cumulatively, since the program began in 1980, more than $96 million in 16
assistance has been provided to nearly 600,000 SCE&G customers. 17
SCE&G’s Project Share, which provides assistance to low-income 18
customers with winter heating bills and, in health-related cases, summer 19
bills, collected over $225,000 in 2011 through contributions from SCE&G 20
customers, employees, and retirees. The Governor’s Office of Economic 21
Opportunity administers this money through local community action 22
42
agencies, which distribute Project Share grants to families and individuals 1
so that 100% of the money goes to people in need. Project Share also 2
provides assistance for customers who have exhausted or are otherwise 3
ineligible for LIHEAP funds. Since the program began in 1986, 4
contributions of almost $8 million have helped more than 44,000 low-5
income SCE&G customers. 6
Q. PLEASE DISCUSS SCE&G’S CUSTOMER GROWTH WITHIN ITS 7
SERVICE TERRITORY SINCE THE LAST RATE PROCEEDING. 8
A. In spite of the stagnant economic conditions, SCE&G experienced 9
customer growth of approximately one percent for the period September, 10
30, 2009, which was the close of the test year in the Company’s last rate 11
proceeding, through December 31, 2011, which is the end of the test year in 12
this proceeding. However, recent industrial economic development 13
announcements have created shifts in demographics resulting in greater 14
growth within defined areas, as construction activities for industrial 15
customers and their suppliers are followed by commercial growth and 16
residential relocation. SCE&G is responsible not only for maintaining 17
areas of its system where growth is limited, but also for constructing 18
infrastructure to effectively serve such demographic shifts in various areas 19
of its service territory. Recent economic development announcements 20
include areas of Lexington, North Charleston, and Aiken. In addition, 21
43
SCE&G continues to witness growth along its coastal service areas, as well 1
as near military installations within its service area. 2
Q. HOW HAS THE AGE OF THE TRANSMISSION SYSTEM 3
AFFECTED INVESTMENT IN IT? 4
A. Much of SCE&G’s transmission system was built in the period 5
between the late 1940s and late 1970s, when the majority of our present 6
generation stations were built and when the major load centers in our 7
service areas were being fully integrated into a single transmission system. 8
In many areas, the capacity for future growth that was built into these assets 9
30 or 40 years ago has been exhausted. In addition, aging physical assets 10
require increased capital investment to maintain their reliability. Since the 11
Company’s prior rate filing, the Company has invested $409 million in both 12
transmission and distribution infrastructure that is included in rate base in 13
this proceeding. 14
Q. IS ENVIRONMENTAL REMEDIATION AN ISSUE THAT THE 15
COMPANY SEEKS TO ADDRESS AS PART OF THIS RATE 16
PROCEEDING? 17
A. Yes. The Company is required to fund environmental remediation 18
activities associated with its electric operations as it becomes aware of 19
environmental issues. The Company seeks the Commission’s approval of a 20
mechanism to recover the costs of such environmental remediation similar 21
to the mechanism approved by the Commission for its gas operations. The 22
44
mechanism will provide a reasonable method of recovery for these required 1
utility operating costs and serve to more accurately match revenue recovery 2
with the incurred costs. Company Witness Swan will provide a more 3
comprehensive explanation of the proposed accounting treatment for the 4
mechanism. My testimony centers on the operational existence and 5
necessity of such costs by providing examples of current environmental 6
remediation requirements. 7
Q. PLEASE EXPLAIN THE ENVIRONMENTAL REMEDIATION 8
BEING UNDERTAKEN BY THE COMPANY REGARDING THE 9
POSSIBLE BURIAL OF CAPACITORS AT CERTAIN CREW 10
QUARTERS. 11
A. Through conversations with employees who worked at the Ashley 12
Phosphate Road Crew Quarters, SCE&G’s Environmental Services 13
Department was made aware that capacitors may have been buried at the 14
site in the past, specifically in the late 1970s time frame. Subsequent 15
interviews with current and retired employees, who would have knowledge 16
of this matter, have led the Company to believe that there is a reasonably 17
high probability that capacitors are indeed buried at this site. Under the 18
1976 Toxic Substances Control Act (“TSCA”), 15 U.S.C. § 2601 et seq., 19
SCE&G has the responsibility to address and remediate issues resulting 20
from the disposal of polychlorinated biphenyl (“PCB”) material, such as 21
capacitors containing PCB. Pursuant to the regulations that implement the 22
45
requirements of the TSCA, SCE&G has notified the Environmental 1
Protection Agency of its plans to investigate and remediate any PCB waste 2
identified as a result of buried capacitors at this site. The Company also 3
has reason to believe, through similar interviews and conversations with 4
current and past employees, that capacitors may have been buried at the site 5
of the Leeds Avenue and Mt. Pleasant Crew Quarters. The Company also 6
is initiating efforts to identify and remediate any PCB waste identified at 7
these additional crew quarters sites as well. The remediation steps will 8
involve identification and removal of the buried capacitors, and removal 9
and destruction of any PCBs from the soil in the affected areas. 10
Q. PLEASE EXPLAIN THE ENVIRONMENTAL REMEDIATION 11
BEING INVESTIGATED BY THE COMPANY WITH RESPECT TO 12
ARSENIC AT CERTAIN COMPANY SUBSTATIONS. 13
A. Based upon an investigation undertaken at its own initiative, the 14
Company has determined that the soil in certain SCE&G substations 15
contains elevated levels of arsenic. The substations at issue are the 16
Graniteville, Fairfax, Yemassee, and Accabee substations. The arsenic 17
resulted from the use many years ago of herbicide containing arsenic to 18
eliminate foliage at the sites on which the substations were to be 19
constructed. There was no prohibition against using herbicides containing 20
arsenic at the time the herbicide was applied to the site. Now, however, the 21
46
arsenic has been identified in the soil and at some point must be 1
remediated. 2
The Company engaged an engineering services company to perform 3
additional assessment and provide remedial options for these sites. The 4
engineering company has proposed several potential remediation options 5
that the Company is evaluating. 6
Q. DOES THIS CONCLUDE YOUR TESTIMONY? 7
A. Yes. It does. 8
