UNITED STATES 

DEPARTMENT OF AGRICULTURE 

RURAL DEVELOPMENT 

RURAL UTILITIES

SERVICE

SUMMARY OF 

ITEMS OF ENGINEERING INTEREST 

OCTOBER 2010 
Items of Engineering Interest 

October 2010 

i 

TABLE OF CONTENTS 

ENGINEERING ............................................................................................................................ 1

An Alternative Approach to Constructing a Substation ............................................................. 1

Separation of Outdoor Oil-Insulated Transformers from Buildings and Other Equipment ...... 2

The Case for Distribution Line Hardening ................................................................................. 3

NESC Conclusion of Alternate Calculation Methods for Load and Strength Factors .............. 5

Horizontal Post Non-ceramic Insulators for Transmission Lines ............................................... 5

OPERATIONS AND MAINTENANCE ..................................................................................... 8

Idle Services ................................................................................................................................ 8

NERC Reliability Update ........................................................................................................... 9

ENVIRONMENTAL .................................................................................................................. 11

SPCC Plan Template for Tier I Qualified Facilities Now Available from EPA ...................... 11

RENEWABLE ENERGY & SMART GRID ........................................................................... 12

RUS Funding of Smart Grid Projects ....................................................................................... 12

ADMINISRATIVE AND OTHER ............................................................................................ 13

RUS Bulletins 1728F-810 and 1728F-811 ............................................................................... 13

Electric Programs News by Email ............................................................................................ 13

Exhibit 1: 2012 NESC Revsision Schedule .............................................................................. 17

APPENDIX A: RUS Electric Staff Division ............................................................................ 18

APPENDIX B: NRECA T&D Engineering Committee .......................................................... 19

 
Items of Engineering Interest 

October 2010 

ii 

ABBREVIATIONS 

AMI Automated Metering Infrastructure 

AMR Automated Meter Reading 

ANSI American National Standards Institute 

BES Bulk Electric System 

CAD Computer Aided Drafting 

CIP Critical Infrastructure Protection 

DLH Distribution Line Hardening 

EC Electric Cooperative 

ECA Electric Cooperative Association 

EMC Electric Membership Corporation 

EPA Electric Power Association 

ESD Electric Staff Division 

FERC Federal Energy Regulatory Commission 

GIS Geographic Information System 

IEEE Institute of Electrical and Electronics Engineers 

IP Informational Publication 

MDCL Maximum Designed Cantilever Load 

MS Modular Substation 

NERC North American Electric Reliability Corporation 

NESC National Electrical Safety Code 

NFPA National Fire Protection Association 

NRD Northern Regional Division 

P&D Paterson & Dewar Engineers, Inc. 

PRC Protection and Control 

REA Rural Electric Association 

RUS Rural Utilities Service 

SCADA Supervisory Control and Data Acquisition 

SRD Southern Regional Division 

TOP Transmission Operations 

USDA United States Department of Agriculture 
Items of Engineering Interest 

October 2010 

1 

ENGINEERING 

An Alternative Approach to Constructing a Substation 

There is an alternative approach to designing and constructing standard substations called the 

“Modular Substation (MS)” approach. Modular substations have been around for some time, but 

recently we have heard more news about this approach. One reason for this is that the modular 

substation approach makes it more cost effective and more appealing now when compared with 

traditional substation construction. Recent improvements in substation equipment technology 

and cost efficiencies in installation and energizing of a modular substation make it more popular 

than a traditional substation. Some utilities have benefited from the short time commissioning 

and flexibility that the modular substation approach offers in site selection. 

A typical modular substation consists of all components, controls, wiring, transformers, 

reclosers, and regulators. All pre-assembled equipment is installed on a self-supporting steel 

base frame. All onboard protection, control, and automation devices are pre-wired and tested 

before delivery to the site. The module then would be ready for quick installation on the 

customer's concrete pier foundations. Site preparation is significantly reduced, and few work 

hours would be required to complete the installation. This approach has resulted in significant 

savings on site work, construction and commissioning time. Completion time for a modular 

substation usually is half of the time that is required to complete traditional substation 

construction. 

In preparation of a MS project, the following advantages can be discussed with managers: 

 Overall lower cost 

 Reduce construction time in half 

 Reduce the required land for MS installation 

 Maximize Safety and security 

 Create MS system that can be easily modified in the future 

 Design MS that is acceptable by the City, State, and County architectural zoning 

requirements 

Modular substation design uses a broad range of applications and provides installation flexibility, 

allowing it to be tailored to the utility's requirements and commissioned within a short time 

frame. The modular substation is an ideal solution for additions or replacement of existing 

substation. Many of industry's leaders in the substation business are now providing modular 

substation fabrication and installations. 

If you would like more information or have any questions, please contact Theodore V. Pejman, 

Electrical Engineer, Transmission Branch, at 202-720-0999 or at Ted.Pejman@wdc.usda.gov. 
Items of Engineering Interest 

October 2010 

2 

Separation of Outdoor Oil-Insulated Transformers 

from Buildings and Other Equipment 

Transformers generally contain the largest quantity of a combustible substance that is located in 

a substation. Therefore, special attention should be given to their location in relation to control 

buildings, other transformers, and other combustible substance filled equipment. Most fires 

related to oil insulated transformers occur as a result of a breakdown of insulation caused by 

overloads, switching or lightning surges, low oil level, moisture in the oil, combustible gas 

accumulation within the transformer tank, or failure of the insulating bushing. Potentially, such 

a fire could cause a considerable amount of burning oil to be expelled over a large area and an 

intense fire could follow. Therefore, the location of transformers in a substation should be of 

concern to the designer and engineer. Every possible attempt should be made to locate oil-filled 

equipment away from substation buildings, other equipment, possible fire hazards present in 

adjacent properties, and similar hazards. 

 

Determination of the physical separation design is based on type and quantity of oil in the 

transformer, size of a postulated oil spill (surface area and depth), type of construction of 

adjacent structures, power rating of the transformer, fire suppression systems provided, and type 

of electrical relaying protection provided. 

Subclause 4.4.1 of IEEE Standard 979, “IEEE Guide for Substation Fire Protection,” states: 

“Transformers containing 2000 gal (7571 L) or more of insulating oil should be at least 

20 ft (6.1 m) from any building. If these large oil-filled transformers are located between 

20 and 50 ft (6.1-15.2 m) of a building, the exposed walls of the building should 

constitute, or be protected by, at least a 2-hour fire-rated barrier. The barrier should 

extend in the vertical and horizontal directions such that any point of the transformer is a 

minimum of 50-ft (15.2 m) from any point on the wall not protected by the barrier. 

Should it be necessary to encroach on the above minimums, the installation of a 

transformer fire protection system should be considered. Some jurisdictions require 

combination of barrier and fire protection systems.” 

Subclause 4.4.2 of IEEE Standard 979, “IEEE Guide for Substation Fire Protection,” states: 

“Transformers containing less than 2000 gal (7571 L) of insulating oil should be 

separated from buildings by the minimum distances shown in the following table: 

Transformer Rating Recommended Minimum

Distance From Building* 

75 kVA or less 10 ft (3.0 m) 

76-333 kVA 20 ft (6.1 m) 

More than 333 kVA 30 ft (9.1 m) 

*Guidance for recommended minimum distances from buildings in 

electric generating plants are given in ANSI/NFPA 850-1992 [B31] and 

ANSI/NFPA 851-1992 [B32]. 
Items of Engineering Interest 

October 2010 

3 

Where a transformer is installed next to a building with less than the minimum distance, the 

building should have fire-resistive wall construction. Guidance can be found in NFPA 255-1992 

[B29], “Standard Method of Test of Surface Burning Characteristics of Building Materials.” 

Separation between large transformers 

Subclause 4.4.3 of IEEE Standard 979, “IEEE Guide for Substation Fire Protection,” states: 

“Large oil-filled transformers should be separated by at least 30 ft (9.1 m) of clear space 

and/or a minimum 1 hour fire-rated barrier.” 

For further recommendations regarding substation fire protection, including “Typical Oil 

Quantities in Equipment,” refer to the IEEE Standard 979, “IEEE Guide for Substation Fire 

Protection,” and NFPA 850-1992, “Recommended Practice for Fire Protection for Electric 

Generating Plants,” especially where this NFPA code has been adopted by authority having 

jurisdiction. If any local code or ordinance is more restrictive than a recommendation listed in 

the NFPA code or the IEEE Standard, then the local code or ordinance should be followed. 

If you like more information or have any question, please contact Mike Eskandary, Electrical 

Engineer, Transmission Branch, at (202) 720-9098 or at Mike.Eskandary@wdc.usda.gov. 

The Case for Distribution Line Hardening

Extreme weather events such as ice storms, hurricanes and tornados are certainly not “new 

news” to RUS borrowers, but it seems that in recent years an increase in the frequency and 

magnitude of such events has been on the minds of nearly everyone. The damage to electrical 

facilities at distribution cooperatives alone has surpassed what many experts ever thought 

possible, and some cooperative members in severely affected areas have spent many long hours 

in the dark waiting for their electric service to be restored. 

The aftermath of such scenes has raised many questions among utilities, customers, regulators, 

and other interested parties, and perhaps the most resounding question to be posed thus far has 

been, “What can be done to eliminate or at least help alleviate the damages caused to electrical 

facilities from extreme weather events?” This question alone has set the wheels of innovation 

and research into motion in a profound way to diligently search for an appropriate answer. Some 

cooperatives are finding at least part of the answer in a concept frequently referred to as 

Distribution Line Hardening (DLH). 

DLH is a term that is now commonly being used in the industry to describe a process (and 

individual actions) in which utilities make changes and improvements to their electric facilities 

as a way of mitigating and avoiding damages from severe weather events. Some state authorities 

have promulgated rules which require jurisdictional distribution utilities to prepare and 

implement DLH plans as part of their normal operations, and many other utilities are engaging in 

such plans as well. 
Items of Engineering Interest 

October 2010 

4 

DLH is a concept whose time has fully come, and most experts expect that it will be an integral 

part of future activities aimed at improving reliability and enhancing the many benefits that will 

eventually be realized through other coming changes such as Smart Grid infrastructure 

deployment. DLH is considered by many utilities as a way of “getting their house in order” to 

show their concern for the customer and willingness to adapt their methods in order to improve 

reliability and service. 

There are many actions that fall into the category of DLH, but experts warn that there are no 

“Silver Bullets” when it comes to completely avoiding utility storm related damages. Even 

though a company may give due diligence to preparation, some damages are inevitable – 

especially in extreme weather events. Despite this fact, most experts also agree that DLH can be 

an extremely valuable asset to utilities, and it can make a tremendous difference in reducing the 

damages that might be expected. Some of the more common DLH tactics that utilities are 

currently engaged in are: 

 Increased right-of-way trimming and improved vegetation management programs 

 Tree replacement programs 

 Danger tree removal 

 Improved sectionalizing schemes (Establishing reliability zones, etc.) 

 Identification and replacement of deteriorated facilities 

 Strengthening critical infrastructure 

 Designing targeted facilities to exceed regulatory and/or NESC requirements 

 Increased inspection and maintenance 

 Improved guying and anchoring methodologies 

 Deploying new technologies 

 Placing more emphasis on joint-use attachments and compliance issues 

 Placing more emphasis on proper engineering and construction practices 

 Strategic conversion of overhead facilities to underground facilities when justifiable 

One interesting caveat concerning the conversion of overhead to underground is the tremendous 

amount of research that has been completed in recent years on this subject. Several states have 

commissioned research projects and many other studies have been compiled as well. While the 

results of these studies are outside the scope of this article, it is interesting to note that thus far no 

state has required the wholesale conversion from overhead to underground. While there are 

several reasons for this, the tremendous costs and unimaginable logistical challenges of such 

conversions are the most important factors. Despite this fact, many authorities and utilities agree 

that there are special circumstances where smaller scale overhead to underground conversions 

would make sense and prove to be justifiable in terms of avoided destruction and costs. 

If you would like more information or have any questions, please contact Steve Conover, 

Patterson & Dewar Engineers, Inc. (P&D) at 606-872-3501or at sconover@pdengineers.com. 

You may also visit the web-site at www.pd-engineers.com . 
Items of Engineering Interest 

October 2010 

5 

NESC Conclusion of Alternate Calculation Methods 

for Load and Strength Factors

As of July 31, 2010, alternative calculation methods using load factors of Table 253-2 and 

strength factors of Table 261-1B of the 2007 National Electrical Safety Cole shall no longer be 

applied. These alternate method tables were older calculations for wood and reinforced (not 

prestressed) concrete structures. The alternative method remained in the National Electric Safety 

Code to allow engineers who continued to use the old method time to implement the change 

over. Notification of the sunset date can be found in Rules 253 and 261 of the 2007 edition of 

the NESC. Tables 253-1 and 261-1A remain as the primary means of determining load and 

strength factors for Rule 250B (district loads), Rule 250C (extreme wind loads), and Rule 250D 

(extreme ice with concurrent wind conditions). 

If you would like more information or have any questions, please call Gabrielle Stokes, 

Electrical Engineer, Transmission Branch, at (202) 720-1924 or at 

Gabrielle.Stokes@wdc.usda.gov. 

Horizontal Post Non-ceramic Insulators for Transmission Lines 

RUS is currently reviewing applications to Technical Standards Committee ‘A’ for accepting 

non-ceramic horizontal post insulators for transmission lines. The accepted insulators will be 

listed in Information Publication 202-1, LIST OF MATERIALS Acceptable for Use on Systems 

of USDA Rural Development Electrification Borrowers. The evaluation guidelines for the 

insulators are given below: 

1. Insulators are to comply with ANSI C29.17-2002, American National Standard for 

Insulators—Composite—Line Post Type or ANSI C29.18, 2003 American National 

Standard for Insulators—Composite—Distribution Line Post Type. The insulators 

will be accepted with clamp end fittings and a rigid curved base or bendable curved 

base for use with round poles and a rigid flat or bendable flat base for flat surface 

poles. The pole mounting bracket should accommodate 7/8 inch bolts spaced 12 

inches apart. Footnotes will be added to manufacturers that offer a two hole blade 

end fitting. 

2. Clamp dimensions are to comply with ANSI C29.7, Porcelain Insulators-High 

Voltage Line-Post Type 

3. For each voltage class, the insulators meet the following:

Insulators mounted on wood and fiberglass poles (rigid curved base or bendable 

curved base)
Items of Engineering Interest 

October 2010 

6 

Voltage

kV

ANSI Class 

(Design Type)

SCL

(Ult. Strength), 

lbs

Min 

MDCL

Lbs

34.5 51-34 2400 1200

46 51-35 2400 1200

69 51-36 2400 1200

115 250-54* 2650 1325

138 250-60* 2300 1150

138 250-66* 2000 1000

 *Note: 2.5 inch rods

Insulators mounted on steel and concrete poles (rigid flat or bendable flat base for 

steel poles or rigid curved base or bendable curved base for centrifugally spun 

concrete poles)

Voltage

kV

ANSI Class 

(Design Type)

SCL

(Ult. Strength), 

lbs

Min 

MDCL

Lbs

34.5 51-36 2400 1200

46 51-36 2400 1200

69 250-41* 3300 1650

115 250-60* 2650 1325

138 250-66* 2300 1150

138 250-75* 2000 1000

*Note: 2.5 inch rods

4. For each voltage class, the insulators with 3.0 inch rods are to meet the following:

Insulators mounted on steel and concrete poles (rigid flat or bendable flat base for 

steel poles and rigid curved base or bendable curved base for centrifugally spun 

concrete poles)

Voltage

kV

ANSI Class 

(Design Type)

See note below 

SCL

(Ult. Strength), 

lbs

MDCL

lbs

115 250-60 4500 2275

138 250-66 3900 1950

138 250-75 3500 1750

Note: Since ANSI C29.17 does not include horizontal posts with 3.0 inch 

diameter fiberglass rods, the design types in this table are given for reference to 

minimum and maximum lengths, minimum CIFO and 60 Hz Flashover Values
Items of Engineering Interest 

October 2010 

7 

If you would like more information or have any questions, please contact Donald Heald, 

Transmission Branch, at (202) 720-9102 or Don.Heald@wdc.usda.gov. 
Items of Engineering Interest 

October 2010 

8 

OPERATIONS AND MAINTENANCE 

Idle Services

The report of Idle Services on the Form 7, Part B, is completely inaccurate for many RUS 

borrowers. Often it is a figure simply carried forward year after year and not considered 

important. Consequently many electric systems erroneously report a high number of idle services 

on the Borrower Statistical Profile. According to RUS Bulletin 1717B-2: The number of idle 

services in Column b should be the total number of delivery points to which service wires remain 

physically in place but for which no bill is being rendered. Seasonal consumers or patrons paying a 

nominal sum for the retention in place of idle facilities should be excluded from the count of idle 

services.

This is a review of a cooperative which has 19,000+ consumers and reports over 3,000 idle 

services on their Form 7. A printout of inactive accounts revealed numerous old accounts, many 

over 10 years old, still on the books as idle services. In a typical example a consumer moved out, 

another consumer moved in and was given a new account number; but the old account was not 

retired and the old account number was not deleted from the system. Other examples include 

houses or barns which were torn down long ago and the services removed but not retired. The 

result is a large number of accounts reported as idle services which are long gone, and the idle 

services and total services in place are overstated. 

Economic impacts of idle services include: increased maintenance expense, increased liability 

exposure, stranded plant, possible line losses, increased depreciation expense. Property taxes 

may also be affected (varies from state to state). 

Solution: Give the inactive printout to the servicemen to review and correct every account. Each 

serviceman knows his area well and many accounts can be checked without even leaving the 

office, however most will have to be physically checked in the field enroute to other jobs or a 

rainy-day job. This will obviously take a long time because it is not a high priority. Then revise 

the report and December Form 7 with a footnote explanation. In the future the report of idle 

services can be kept up to date with GIS and proper retirement procedures. There are 2 separate 

issues to address: 1) correct the report of idle services, and 2) physically remove idle services in 

the field. 

One cooperative brought in all transformers that had not been active for 6 months – several 

hundred transformers – most of which went back into inventory. Recommendation: flag 12 

months and let the servicemen use judgment if they know of a location where somebody might 

be moving back in reasonably soon. Note: this did not correct the report of idle services. It still 

takes the process discussed above to produce an accurate report. 
Items of Engineering Interest 

October 2010 

9 

Remember, all numbers reported on the Form 7 are supposed to be accurate and certified by the 

manager. The report of idle services may be more important than you think and should be as 

accurate as possible. 

If you would like more information or have any questions, please contact Mike J. Norman, GFR 

(IN, KY, TN) – Northern Regional Division at Mike.Norman@wdc.usda.gov. 

NERC Reliability Update 

The era of mandatory compliance to grid reliability standards began in June 2007. Presently, 

there are fifty (50) Generation & Transmission cooperatives and approximately one hundred and 

fifteen (115) distribution cooperatives included on the North American Electric Reliability 

Corporation (NERC) Compliance Registry. These registered entities are responsible for 

compliance to over ninety (90); Federal Energy Regulatory Commission (FERC) approved 

reliability standards. 

NERC has issued penalties for one or more violations to hundreds of utilities and it is expected 

that many more penalties, will be issued throughout 2010. A majority of the violations 

discovered in the early stages of the program where assessed as $0 penalties, however, financial 

penalties issued range from $1,500 to $25 million. Sixteen cooperatives have received 

financial penalties ranging from $1,500 to $125,000. 

To date, cooperatives represent approximately 11.7 % of the total number of violations. The top 

violated standards for cooperatives are PRC-005 - Transmission and Generation Protection 

System Maintenance and Testing, CIP-001 - Sabotage Reporting, TOP-002 - Normal 

Operations Planning, PRC-008 - Implementation and Documentation of Underfrequency Load 

Shedding Equipment Maintenance Program, and CIP-004 - Cyber Security - Personnel & 

Training. Of the CIP-001 violations, 92 % are mitigated. 

Since PRC-005 is the standard most violated by cooperatives it is important to understand its 

purpose, applicability and the actual violations. The purpose of this standard is “to ensure all 

transmission and generation Protection Systems affecting the reliability of the Bulk Electric 

System (BES) are maintained and tested”. It is applicable to entities registered as Transmission 

Owners, Generator Owners and Distribution Providers that own a transmission Protection 

System. From the NERC Glossary of Terms a Protection System is defined as “protective relays, 

associated communication systems, voltage and current sensing devices, station batteries and DC 

control circuitry”. 

The violations of PRC-005 include the following: 

 The cooperative failed to: 

o document procedure for testing DC control circuitry 
Items of Engineering Interest 

October 2010 

10 

o provide evidence of having a Protection System maintenance and testing program 

for all types of Protection Systems 

o provide summary of maintenance and testing procedures 

o provide basis for intervals in program 

 The cooperative did not: 

o have a Protection System Maintenance and Testing Program for its newly 

installed Protection System 

o notify reliability entities of relay or equipment failures 

o coordinate changes to its protection systems as required by the standard 

o maintain and test within the defined intervals 

It is critical for cooperatives that are included on the NERC Compliance Registry to understand 

the requirements of the reliability standards associated with its functional registration. Noncompliance can subject a registered entity to financial and other types of penalties. Additional 

information about reliability standards, violations and penalties are available on the NERC 

website (http://www.nerc.com). 

If you have any questions, please contact Patti Metro, Manager, Transmission and Reliability 

Standards, National Rural Electric Cooperative Association at 703-907-5817 or at 

patti.metro@nreca.coop. 
Items of Engineering Interest 

October 2010 

11 

ENVIRONMENTAL 

SPCC Plan Template for Tier I Qualified Facilities Now Available from EPA

As you know, NRECA pushed very hard to have EPA streamline the requirements for Spill 

Prevention, Control and Countermeasure (SPCC) plans as they apply to small facilities like 

substations. We worked with other small business representatives through the SBA to help EPA 

develop a template that companies could use to satisfy the SPCC requirements. As we 

announced in earlier memos, EPA issued final amendments to the SPCC regulations in the 

Federal Register at 73 F.R. 74307 (December 5, 2008) that addressed “Tier I Qualified 

Facilities”. The amendments included a template that those facilities could use instead of having 

to draw up an individual plan. The final amendments did not become effective, however, until 

January 14, 2010. While these regulations are now finally effective, the template was only 

available by making paper copies of the forms contained in the December 5, 2008 Federal 

Register publication. 

In response to requests from NRECA and other groups, EPA has now made the SPCC plan 

template available in a form that can be filled out electronically and they have just posted it on 

their webpage at: http://www.epa.gov/emergencies/content/spcc/tier1temp.htm. This should 

make it much easier for small co-operatives to avail themselves of the streamlined SPCC 

requirements. 

If you would like more information or have any questions, please contact Jim Stine at 

703-907-5739 or at james.stine@nreca.coop. 

 
Items of Engineering Interest 

October 2010 

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RENEWABLE ENERGY & SMART GRID 

RUS Funding of Smart Grid Projects 

The concept of Smart Grid has taken off recently (i.e. the past 2 years). With the advent of 

ARRA funding via Department of Energy’s (DOE) “Smart Grid Investment Grants” and Smart 

Grid Demonstration Projects” programs, RUS seeks to supplement the cooperatives’ plans by 

providing funding for those cooperatives that received grants and also those who did not. The 

idea of a smarter grid is nothing new to the rural cooperatives community as this type of 

infrastructure has been used for more than 10 years. Cooperatives have been deploying 

Automated Meter Reading (AMR), Automated Metering Infrastructure (AMI) and Supervisory 

Control and Data Acquisition (SCADA) systems to better serve their membership as well as 

improve efficiencies within the system. So, cooperatives are well ahead of the curve on Smart 

Grid. 

RUS is providing funding for Smart Grid infrastructure projects. Approval authority lies within 

the Regional Offices, Northern Regional Division (NRD) and Southern Regional Division 

(SRD), with the materials/equipment review being handled by Electric Staff Division (ESD). 

For the short term, these projects are being handled as a “non-standard materials/equipment” 

basis. The goal is to eventually have more of the associated equipment added to IP 202-1 List of 

Materials. In fact, some of the metering associated with smarter systems is already included in 

the List of Materials. 

The following are some preliminary items that should accompany an application for Smart Grid 

project funding: 

 CWP or Amended CWP 

 Overall scope of the project 

 Cost/benefit analysis (similar to that of AMR/AMI) 

 Technical information on the proposed equipment 

 Itemized list of the proposed equipment, including number of units and unit cost 

If you would like more information or have any questions, please contact Norris Nicholson, 

Chair – Technical Standards Committee “A” (Electric) at 202-720-1979 or at 

Norris.Nicholson@wdc.usda.gov. 

 
Items of Engineering Interest 

October 2010 

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ADMINISRATIVE AND OTHER 

RUS Bulletins 1728F-810 and 1728F-811

RUS Bulletins 1728F-810 and 1728F-811, Electric Transmission Specifications and Drawings 

for 34.5 kV through 69 kV and 115 kV through 230 kV is currently under revision. The revision 

updates the written part of the construction specifications. The drawings will be in AutoCAD 

format and include a new assembly drawing and a new guide drawing. 

RUS is in the process of accepting non-ceramic horizontal post insulators for transmission lines 

with voltages 34.5 kV to 138 kV. As such, there will be a horizontal post assembly unit for nonceramic insulators added to the drawings. There will also be guide drawing for setting depths of 

multiple pole structures. 

Because the revised document will need to go through the Federal Register process, the projected 

date for the document to appear on the RUS website is not clear. 

If you would like more information or have any questions, please contact Donald Heald, 

Transmission Branch, at (202) 720-9102 or Don.Heald@wdc.usda.gov. 

Electric Programs News by Email

Borrowers and other interested parties are able to receive RUS Electric Programs news and 

updates by joining our mailing list. By signing up for the mailing list, borrowers shall have 

access to new and revised publications, Federal Register issuances, and more. 

To receive updates, simply follow the step-by-step instructions below. 

1. Go to http://www.usda.gov/rus/electric/index.htm

Notice the News Spotlight border to the right of the screen. 
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2. Scroll to the bottom of the page. Notice the announcement, “Are you interested in 

receiving email updates from Electric Programs...” Click the eMail News and 

Information link. 

3. You will be redirected to the following page. Insert the desired email address where you 

would like to receive Electric Programs updates. 
Items of Engineering Interest 

October 2010 

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4. Scroll down to the Rural Development Utilities Programs section and select Electric 

Program News check box under Electric Program 
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5. Scroll to the bottom of the page and press SUBSCRIBE. 

Attention: You will be redirected to the same page, please repeat steps 3 through 5. 

6. After you have successfully subscribed, you will be redirected to the following page for 

confirmation. The system will then send a confirmation email. 

The RUS website is undergoing updates; appearance is subject to change. 

If you would like more information or have any questions, please call Gabrielle Stokes, 

Electrical Engineer, Transmission Branch, at (202) 720-1924 or 

Gabrielle.Stokes@wdc.usda.gov. 
Items of Engineering Interest 

October 2010 

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Exhibit 1 

Time Schedule for the Next Revision of the 

National Electrical Safety Code

The revision schedule for the 2012 NESC is as follows: 

September-October 2010 Period for NESC Subcommittee Working Groups and NESC 

Subcommittees to reconsider all recommendations concerning the 

proposed amendments and prepare final report. 

15 January 2011 Proposed revision of the NESC, Accredited Standards Committee 

C2, submitted to NESC Committee for letter ballot and to ANSI 

for concurrent public review. 

15 May 2011 NESC Committee approved revisions on the NESC submitted to 

ANSI for recognition as an ANSI standard. 

1 August 2011 Publication of the 2012 Edition of the NESC. 

You can find detailed NESC information on IEEE’s NESC website: 

http://standards.ieee.org/nesc/index.html . 
Items of Engineering Interest 

October 2010 

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APPENDIX A 

RURAL UTILITIES SERVICE ELECTRIC STAFF DIVISION

Electric Staff Division 

Room 1246 - Stop 1569 

1400 Independence Avenue, SW 

Washington DC 20250-1569 

FAX: (202) 720-7491 

Name Title E-mail Telephone

Office of the Director 

Georg A. Shultz Director georg.shultz@wdc.usda.gov (202) 720-1900 

Lorraine Henderson-Simpkins Secretary lorraine.simpkins@wdc.usda.gov (202) 720-1900 

Marshall Duvall Staff Engineer marshall.duvall@wdc.usda.gov (202) 720-0096 

Robin Meigel Financial Specialist robin.meigel@wdc.usda.gov (202) 720-9452 

 

Distribution Branch 

Donald Junta Branch Chief donald.junta@wdc.usda.gov (202) 720-1920 

Trung Hiu Electrical Engineer trung.hiu@wdc.usda.gov (202) 720-1877 

Gerard Moore Electrical Engineer gerard.moore@wdc.usda.gov (202) 205-9692 

 

Energy Forecasting Branch 

Vacant Branch Chief (202) 720-1920 

Sharon Ashurst Senior Load Forecast Officer sharon.ashurst@wdc.usda.gov (202) 720-1925 

 

Transmission Branch 

H. Robert Lash Branch Chief bob.lash@wdc.usda.gov (202) 720-0486 

Mike Eskandary Electrical Engineer mike.eskandary@wdc.usda.gov (202) 720-9098 

Ted Pejman Electrical Engineer ted.pejman@wdc.usda.gov (202) 720-0999 

Gabrielle Stokes Electrical Engineer gabrielle.stokes@wdc.usda.gov (202) 720-1924 

 

Technical Standards Committee "A" 

Norris Nicholson Chair norris.nicholson@wdc.usda.gov (202) 720-0980 

Vacant Secretary (202) 720-0980 

 

 
Items of Engineering Interest 

October 2010 

19 

APPENDIX B 

NRECA TRANSMISSION & DISTRIBUTION 

ENGINEERING COMMITTEE 

Member Organization Location 

T&D Executive Committee 

David Mohre, CHAIR NRECA Arlington, VA 

Overhead Distribution Lines Subcommittee 

Clive Buttrey Middle Tennessee EMC Murfreesboro, TN 

James Byrne Poudre Valley REA Fort Collins, CO 

Titus (Ty) Diamond Flint EMC Warner Robbins, GA 

L. Allan Glidewell Southwest Tennessee EMC Brownsville, TN 

Robby Hamlin CoServ Electric Corinth, TX 

Tom Hoffman Agralite EC Benson, MN 

Chad Kirkpatrick Fort Loudoun EC Vonore, TN 

Kevin Mara GDS Associates, Inc. Marietta, GA 

Gerard Moore RUS Washington, DC 

Ernest Neubauer, CHAIR Southern Rivers Energy Barnesville, GA 

Matthew O’Shea STAR Energy Services, LLC Alexandria, MN 

Mike Pehosh NRECA Arlington, VA 

Kenneth Raming Ozark EC Nixa, MO 

Terry Rosenthal Laclede EC Lebanon, MO 

Hossein (Hank) Zarandi Northern Virginia EC (NOVEC) Gainesville, VA 

 
Items of Engineering Interest 

October 2010 

20 

Substation Subcommittee 

Mike Avant Garkane Energy Co-op Loa, UT 

Thomas Barnette Berkeley EC, Inc. Moncks Corner, SC 

Mike Eskandary RUS Washington, DC 

Bradley Hicks, CHAIR New Horizon EC, Inc. Laurens, SC 

Shawn Higbe McCall-Thomas Engineering Co., 

Inc. 

Orangeburg, SC 

Ken Malone Middle Tennessee EMC Murfreesboro, TN 

Jared Newton Great River Energy Elk River, MN 

Mike Pehosh NRECA Arlington, VA 

Kirk Powell Burns & McDonnell Engineering 

Co., Inc. 

Houston, TX 

Kevin Seesholtz South Central Power Co. Lancaster, OH 

Kevin White Northeast Missouri Elec. Power 

Co-op 

Palmyra, MO 

System Planning Subcommittee 

Robin Blanton Piedmont EMC Hillsborough, NC 

Robert Dew Hi-Line Engineering, LLC Marietta, GA 

Joe Dorough Jackson EMC Jefferson, GA 

Patrick Grace Oklahoma EC Norman, OK 

Brad Hicks New Horizon EC Laurens, SC 

Jonathan Joyce, CHAIR First Electric Cooperative Corp. Jacksonville, AR 

Donald Junta RUS Washington, DC 

Tim Mobley Berkeley EC Moncks Corner, SC 

Joe Perry Patterson & Dewar Engineers, Inc. Norcross, GA 

Robert Saint NRECA Arlington, VA 

Tim Sharp Salt River Electric Cooperative 

Corp. 

Bardstown, KY 

Joseph Sowell Georgia Transmission Corp. Tucker, GA 

Brian Tomlinson Power Engineers Ft. Worth, TX 

Patrick Williams East Mississippi EPA Meridian, MS 

Kenneth Winder Moon Lake Electric Association, 

Inc. 

Roosevelt, UT 

 
Items of Engineering Interest 

October 2010 

21 

Power Quality Subcommittee 

Tracy Bensley Jackson Purchase Energy Corp. Paducah, KY 

Ed Bevers Rural Electric Co-op, Inc. Lindsay, OK 

Scott Blecke Great Lakes Energy Cooperative Boyne City, MI 

Chris Brewer, CHAIR Blue Grass Energy Co-op, Corp. Nicholasville, KY 

Robert Casey Georgia Transmission Corp. Tucker, GA 

Jeff Coleman Berkeley EC Moncks Corner, SC 

Herman Dyal Clay Electric Cooperative, Inc. Keystone Heights, FL 

Christopher Melhorn EPRI Knoxville, TN 

David Mueller Electrotek Concepts, Inc. Knoxville, TN 

Ted Pejman RUS Washington, DC 

Alvin Razon NRECA Arlington, VA 

Lewis Shaw Brunswick EMC Shallotte, NC 

Eric Sonju Power System Engineering, Inc. Madison, WI 

Mike Swearingen Tri-County Electric Cooperative, Inc. Hooker, OK 

Michael Watson Duck River EMC Shelbyville, TN 

 

 

Overhead Transmission Line Subcommittee 

Dominic Ballard East Kentucky Power Coop Winchester, KY 

Bob Beadle, Chair North Carolina EMC Raleigh, NC 

Thom Beckett Beckett and LaRue, Inc. Longwood, FL 

Patrick Dille Tri-State G&T Assn., Inc. Denver, CO 

Quan He Fan Georgia Transmission Corp. Tucker, GA 

Don Heald RUS Washington, DC 

Charles Lukkarila Great River Energy Maple Grove, MN 

Bubba McCall Georgia Transmission Corp. Tucker, GA 

Patti Metro NRECA Arlington, VA 

Erik Ruggeri Power Engineers, Inc. Hailey, ID 

Aaron Shambrock South Central Power Company Lancaster, OH 

Gabrielle Stokes RUS Washington, DC 

John Twitty PowerSouth Energy Cooperative Andalusia, AL 
Items of Engineering Interest 

October 2010 

22 

Underground Distribution Subcommittee 

Russ Dantzler Mid-Carolina Electric Co-op, Inc. Lexington, SC 

Archie Davis Palmetto Electric Co-op, Inc. Hardeeville, SC 

Robert Emgarten, CHAIR Iowa Lakes Electric Co-op Estherville, IA 

Steven Gwin Warren RECC Bowling Green, KY 

Trung Hiu RUS Washington, DC 

Michael Ray Judd Allgeier, Martin & Associates, Inc. Joplin, MO 

John Laughlin Kandiyohi Power Co-op Willmar, MN 

Robert Maxwell Surry-Yadkin Electric Membership 

Corp. 

Dobson, NC 

Horace Necaise Singing River Electric Power Assn. Lucedale, MS 

Kevin Ogles Middle Tennessee EMC Murfreesboro, TN 

Mike Pehosh NRECA Arlington, VA 

Les Shankland Mountain Parks Electric, Inc. Granby, CO 

Scott Wehler Adams Electric Co-op, Inc. Gettysburg, PA