UNITED STATES DEPARTMENT OF AGRICULTURE 

Rural Utilities Service 

BULLETIN 1724D-101A 

RD-GD-2017-85

SUBJECT: Electric System Long-Range Planning Guide

TO: All Electric Bo1rnwers

EFFECTIVE DATE: Date of Approval

OFFICE OF PRIMARY INTEREST: Engineering Standards Branch, Office of Policy, 

Outreach, and Standards

INSTRUCTIONS: This Bulletin replaces Bulletin 1724D-101A, Electric System Long-Range

Planning Guide, dated May 10, 1995.

AVAILABILITY: This bulletin can be accessed via Internet at: 

http://www.rurdev. usda. gov /RD U Bulletins Electric.html 

PURPOSE: The purpose of this guide is to highlight the key engineering principles and 

methods used in the preparation of long-range plans that will assure sound, longrange economic conclusions for owners, engineers, and consultants. 

Assistant Administrator 

Electric Program 

Date 

Disclaimer: The contents of this guidance document does not have the force and effect of law and is not 

meant to bind the public in any way. This document is intended only to provide clarity to the public 

regarding existing requirements under the law or agency policies.
RUS Bulletin 1724D-101A

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TABLE OF CONTENTS

1 Purpose................................................................................................................................... 8

2 The Long-Range Planning Process........................................................................................ 8

3 Phase 1—Collect and Evaluate System Data....................................................................... 10

4 Phase 2—Define Engineering and Economic Criteria......................................................... 14

5 Phase 3—Develop Design Options and Cost Allocations................................................... 17

6 Phase 4—Select and Validate Preferred Plan ...................................................................... 19

7 Phase 5—Develop Plan for Implementing Long-Range Plan ............................................. 22

8 Phase 6—Complete Report and System Circuit Diagrams.................................................. 23

9 Phase 7—Present Final Report for Board Approval............................................................ 24

10 Special Considerations......................................................................................................... 25

11 Use of the Long-Range Plan to Guide System Changes...................................................... 30

12 Power Supply Studies.......................................................................................................... 31

13 Periodic Determination of Plan Validity.............................................................................. 31

14 Conclusion ........................................................................................................................... 32

Exhibits

Exhibit A: Summary of Data Required

Exhibit B: Sample Engineering and Economic Criteria

Exhibit C: RUS Fixed Charge Rate Calculation Guide

Exhibit D: Radial Transmission Line Reliability and Operational Assessment

Exhibit E: Sample Economic Conductor Life System Analysis

Exhibit F: Sample Substation Loading Sheet for Specific Plan

Exhibit G: Sample Plan Economic Analysis Spreadsheet

Exhibit H: Sample Sensitivity Analyses

Exhibit I: Suggested Table of Contents for Long-Range Engineering Plan

Exhibit J: Suggested Table of Contents of Supporting Data

Exhibit K: Checklist of Long-Range Planning Report (RUS Form 260)

Exhibit L: Summary of Long-Range Planning Report (RUS Form 261)

Appendices

Appendix 1: Economic Conductor Life Cycle Analysis

Appendix 2: Radial Transmission Line Reliability and Operational Assessment

Appendix 3: Aging Considerations for Long-Range Capital Expenditures

Appendix 4: Distributed Generation in Long-Range Planning

Appendix 5: Bibliography and References

INDEX:

Distribution System Design and Construction Budget

Long-Range Plan

System Configuration and Operation
RUS Bulletin 1724D-101A

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ABBREVIATIONS

$D Distribution Costs (Plan PW for OOS)

$DP Delivery Point Surcharge Costs (PW for OOS)

$LD Primary Line Losses (Plan PW at Distributor/Cooperative Costs for OOS)

$LPS Primary Line Losses (Plan PW at Power Supplier Costs for OOS)

$S Substation Costs (Plan PW for OOS)

$TL Transmission Line Costs (Plan PW for OOS)

AAC All-Aluminum Conductor

AAAC All-Aluminum Alloy Conductor

ACAR Aluminum Conductor, Alloy-Reinforced

ACSR Aluminum Conductor, Steel-Reinforced

AFC Annual Fixed Charges

AMR Automated Meter Reading

APP Alternate Preferred Plan

CFR Code of Federal Regulations

CPR Continuing Plant Records

CRN Cooperative Research Network

CU Copper

CWP Construction Work Plan

DA Distribution Automation

DG Distributed Generation

EEC Engineering and Economic (Design) Criteria

FERC Federal Energy Regulatory Commission

G&T Generation and Transmission Cooperative

GFR General Field Representative

GIS Geographical Information System

HMW High Molecular Weight (Underground Power Cable Type)

IEEE Institute of Electrical and Electronics Engineers

kcmil Thousand Circular Mil

KWh Kilowatt-hours

LDSF Load Distance Service Factor

LF Load Forecast

LL Long Level (of LRP)

LR Long-Range

LRP Long-Range Plan

LRPG Long-Range Planning Guide

MW Megawatts

NERC North American Energy Reliability Council

NESC National Electric Safety Code

NRECA National Rural Electric Cooperative Association

OOS One-Ownership Study

O&M Operations and Maintenance

PCB Polychlorinated Biphenyl

PP Preferred Plan

PSS Power Supply Study
RUS Bulletin 1724D-101A

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PV Photovoltaic

PW Present Worth

REA Rural Electrification Administration

ROW Right-of-Way for Distribution and Transmission Lines

RTL Radial Transmission Line

RUS Rural Utilities Service

SAIDI System Average Interruption Duration Index

SCADA Supervisory Control and Data Acquisition

TIER Times Interest Earnings Ratio

T/L Transmission Line

UL Underwriters Laboratories

URD Underground Residential Distribution

VAR Volt-Ampere Reactive

XLPE Cross-Linked Polyethylene

DEFINITIONS

Alternate Preferred Plan (APP). The APP is the long-range plan determined by the planning 

engineer and support team to be the best system approach to serve the future long-range loads if

certain parameters assumed in the study significantly change. Such parameters include, but are 

not limited to, large increase in power costs; large increase in wheeling costs; significant changes 

in wholesale rate structure, such as transmission lines; new transmission lines become available 

for use; significant changes in load growth, etc.

Annual Fixed Charges (AFC). The AFC or fixed charge rate is used to annualize capital cost 

expenditures in economic analyses. The rate is calculated by adding up all annual system 

expenses and dividing them by the total number of utility plants installed. Often the rate is 

calculated for a period (e.g., five years) and then averaged. The expense accounts typically used 

are capital interest costs, operations, maintenance, depreciation, and taxes (if applicable). To 

illustrate, a project is estimated to have a total cost of $2,000,000. If the AFC has been 

calculated at 15%, then the annualized costs would be $300,000 (15% × $2,000,000). This 

implies that if the project is constructed and $2,000,000 is added to the electric plant capital 

costs, it is going to take $300,000 per year to fully pay for all the operating expenses. 

See Exhibit C of this Guide for an example of the calculations.

Board. The Board is the Board of Directors and trustees of the Owner. The Board is responsible 

for setting policy, including final approval of the LRP.

Borrower. A Borrower is an organization which seeks a loan from, or to arrange financing 

through, the RUS for the purpose of constructing facilities or making improvements to its 

electric system.

Distribution Automation (DA). DA enables an electric utility to monitor, coordinate, and operate 

electric system and consumer components in real-time from remote locations.
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Distributed Generation (DG). DG—also called on-site generation, dispersed generation, 

decentralized generation, or distributed energy—generates electricity from many small, localized 

energy sources. Most industrial electric generation is from large, centralized facilities, such as 

fossil fuel plants (coal- and gas-powered), nuclear power plants, large solar or wind power farms, 

or hydropower plants. These large plants have excellent economies of scale, but usually transmit 

electricity for long distances through transmission lines and substations that sometimes 

negatively impact the environment.

Economic Conductor Life Analysis. The most economical type of lines can be determined by 

comparing the life costs of various distribution line conductors. The costs are based on the AFC 

rate, the cost of capital to build the line, and the estimated line losses based on projected loading 

and power costs. See Exhibit E of this Guide for an example of the calculations.

One-Ownership Study (OOS). OOS refers to the economic analysis of an electrical system 

where all owners of the various parts of the system (e.g., transmission lines, substations, 

distribution lines, etc.) are considered together as one entity. The study includes the costs for all 

owners and considers each alternate plan in order to identify the most economical approach, 

while taking into account all organizations and their costs.

Owner. The party (or parties) that operate and control the electric system. An electric system 

typically has many components which include, but are not limited to, the distribution lines, 

substations, subtransmission lines, and transmission lines. Typically, in the United States, 

ownership of such components is by one or more parties. The responsibilities of the Owner are 

generally carried out by the general manager, executive, or person of similar title, who is 

principally accountable for overseeing the property.

Planning Engineer. The planning engineer is the individual responsible for conducting all 

necessary studies associated with the LRP, including the preparation of the final report. It is 

desirable that this individual be a duly-registered professional engineer under the state laws of 

the electric system and recognized by RUS as being qualified in preparing LRPs. Although the 

planning engineer is usually an outside consultant, he or she may be a member of the owner’s 

staff or combination of the two. Although many owners’ staff engineers compile CWPs, each 

owner should evaluate the advantage of additional perspectives, skills, and availability of time 

provided by an outside consultant when involved in the LRP.

Power Supplier. The Power Supplier is an organization from which the Owner purchases 

wholesale power and energy. The role of the power supplier may be filled by a private investorowned power company, a governmental agency, or a generation and transmission (G&T) 

cooperative of which the Owner is a member. In many cases, the owner purchases energy from 

more than one power supplier. In cases where all purchases are coordinated through one 

organization, that organization is the power supplier even if it has no generating capacity of its 

own.

Power Supply Study (PSS). PSS refers to studies completed separately from the LRP. The LRP 

is completed using, generally, average facility costs and assumptions for substation and delivery 

point locations. When CWPs are being prepared, PSS are generally completed for certain 
RUS Bulletin 1724D-101A

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portions of the system to formally justify the construction of certain projects, such as 

transmission lines, substations, etc. The PSS is completed in conjunction with the power 

supplier and transmission line/substation owners using precise budgetary estimates. Typically, 

the PSS validates the LRP and allows the projects to be budgeted for construction.

Preferred Plan (PP). The PP is the LRP determined by the planning engineer and support team to 

be the best system approach to serve long-range future loads. The PP is the option that should be 

followed for all planned future construction in CWPs.

Radial Transmission Lines (RTL). RTL refers to transmission lines that feed one or more 

delivery points that are electrically fed from only one source. No alternate loop feed is available 

for an RTL.

Sensitivity Analysis. After determining the costs for each plan evaluated and the Preferred Plan 

appears to have been identified, it is important to compare the plans if certain economic 

parameters varied from what was projected. This process is called the Sensitivity Analysis and is 

usually carried out for the plans with the closest lowest costs. Parameters typically covered in 

the analysis include construction inflation rate, load growth, energy inflation rate, present worth 

rate, and wheeling costs. See Exhibit H of this Guide for an example of such analysis.

Smart Grid Technology. This term refers to the new technology available to the electric 

distribution system for improved operation, protection, and efficiency. The technology is a big 

step in Distributed Automation, allowing system equipment to record events—and appropriately 

respond—for improved system performance. Equipment that supports the Smart Grid 

Technology includes automatic meter information systems, protective relays of substation feeder 

breakers, line controlled switches and reclosers allowing for fault isolation and load transfers, 

etc.

Substation Firm Capacity. Substation Firm Capacity is a term that refers to an electric 

distribution system that has a spare substation transformer or mobile substation or transformer 

available for each of the transformer sizes, voltages, etc., on the system. The spare transformer

may be stored at a substation or in the equipment storage yard. System firm capacity implies that 

spare transformers are stored at some location on the system. Site firm capacity implies that the 

spare transformer is stored at the substation for which it is intended, the result of which improves 

reliability and aids in system O&M. This is often the practice of some systems where there are 

loads that have paid for such capacity or where loads are critical and high-priority in nature.

System Circuit Diagram. The System Circuit Diagram is typically an electric system map 

showing only electric plant components, such as distribution lines, substations, transmission 

lines, and some key, land-based information. The map is clear of a lot of details so that planned 

construction can be shown plainly. The diagram should include line voltage, loading, and 

voltage drops. The map is used to show planned construction for each LRP, including the load 

level to which they are to be built. The maps can be paper or digital in form.

System Planning. System Planning is the careful evaluation of an electric power system, the 

consideration of alternative methods of meeting the electric power needs of the consumers, and 
RUS Bulletin 1724D-101A

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the selection of the most promising of the viable alternatives for providing economical, reliable, 

environmentally acceptable service at a reasonable cost. System Planning by RUS borrowers is 

manifested in the long-range plan (LRP) and the construction work plan (CWP).

CONTRIBUTORS

The United States Department of Agriculture Rural Utilities Service acknowledges the 

dedication and technical expertise of all the organizations and individuals who participated in the 

development of this guide. This guide is designed to help borrowers develop and implement 

long-range options and plans effectively. This document is based on inputs from members of the 

NRECA Transmission and Distribution System Planning Subcommittee. Committee members 

and associates who provided invaluable assistance in preparing this document were:

Name Organization City, State

Brian Bartos Bandera Electric Cooperative Bandera, TX.

Robin Blanton A & N Electric Cooperative Tasley, VA.

Bob Dew High-Line Engineering Marietta, GA.

Joe Dorough Jackson EMC Jefferson, GA.

Patrick Grace Oklahoma Electric Cooperative Norman, OK.

Jon Joyce First Electric Cooperative Corp. Jacksonville, AR.

Donald Junta USDA-RUS Washington, D.C.

Troy Knutson Cass County Electric Cooperative Fargo, N.D.

Tim Mobley Berkeley Electric Cooperative Moncks Corner, S.C.

Joe Perry Patterson & Dewar Engineers Norcross, GA.

Louis Riggs USDA-RUS Washington, D.C (No longer with 

RUS).

Kenneth Rush USDA-RUS Liaison Washington, D.C.

Bob Saint NRECA Liaison Arlington, VA.

Tim Sharp Salt River Electric Cooperative Bardstown, KY.

Joe Sowell Georgia Transmission Corporation Tucker, GA.

Brian Tomlinson Power Engineers Ft. Worth, TX.

Pat Williams East MS Electric Pwr. Association Meridian, MS.

Ken Winder Moon Lake Electric Association Roosevelt, UT.
RUS Bulletin 1724D-101A

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1 PURPOSE

This document is intended to provide guidance in the preparation of long-range plans for 

electric borrowers. It addresses the minimum requirements and responsibilities of system 

owners, engineers and consultants, and it identifies key engineering principles and 

methods for reaching sound long-range economic decisions. This guide supports the 

RUS regulations found in 7CFR1710.250 and replaces existing RUS Bulletin 1724D101A.

2 THE LONG-RANGE PLANNING PROCESS

Every electric distribution borrower has a responsibility to develop plans for serving 

existing and future system loads while maintaining customer satisfaction and meeting 

environmental requirements. Therefore, it is prudent practice for borrowers and their key 

stakeholders to engage in a structured planning process to develop a long-range plan for 

achieving those goals. This resulting plan is an engineering and management tool that 

provides guidelines for operating and expanding the electric distribution system. At a 

minimum, the long-range plan should:

• Determine the most practical and economical means of serving existing and future 

system loads while maintaining reliable service; 

• Identify changes, such as additions, upgrades or retirements of facilities and delivery 

points, as they are needed in order to meet system requirements; and

• Estimate capital requirements for implementing the recommended plan.

In most cases, the borrower’s planning engineer is responsible for managing the planning 

process, including conducting all necessary studies and preparing the long-range plan for 

review and approval by the borrower’s senior management and board of directors and 

others as necessary. The planning engineer may be a member of the borrower’s staff or a 

consultant, or these responsibilities may be shared between staff and consultants. 

The planning process utilized and long-range plan produced, including all load forecasts, 

should comply with all applicable state or other regulatory requirements.

a Study Phases

This guide outlines a seven-phase process for developing the long-range plan. It 

identifies the primary steps in each phase and highlights critical coordination 

issues. The process includes:

• Phase 1—Collect and evaluate system data,

• Phase 2—Define engineering and economic criteria or parameters to be used 

in the study, 

• Phase 3—Evaluate design options and cost allocations,

• Phase 4—Select and validate preferred plan,

• Phase 5—Develop transition plans and maps,
RUS Bulletin 1724D-101A

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• Phase 6—Complete report and system circuit diagrams and

• Phase 7—Present report and obtain final approval.

It may be desirable to undertake some individual tasks from different phases of 

the process concurrently, but it is prudent to consider the impact this may have on 

the overall results. The information collected and decisions made in each phase 

provide the basis for analysis in subsequent phases. That makes it important to 

complete the phases in the order suggested. Otherwise, revisions in one phase 

could result in the need for revisions to work already undertaken in subsequent 

phases. This could delay project completion and potentially increase costs. 

b Consultation with Key Stakeholders

It is important for the borrower to coordinate planning activities with other key 

stakeholders, including the borrower’s power supplier, RUS and other lender if 

necessary. In most cases, the power supplier is also the transmission service 

provider. If there is a separate transmission service provider, both the power 

supplier and the transmission service provider should be included in planning 

process. For convenience, references to power suppliers in this bulletin are 

understood to include transmission providers.

It is prudent to provide essential information to stakeholders in printed or 

electronic form. In addition, the borrower should conduct at least four 

stakeholder meetings to ensure that each organization’s interests are adequately 

considered and addressed:

• Meeting 1—Preliminary conference for discussion of distribution system data;

• Meeting 2—Engineering and economic criteria conference for review,

discussion, and comment on design criteria;

• Meeting 3—Preferred plan review to present preferred plan, economic 

analysis and sensitivity studies to key stakeholders; and

• Meeting 4—Final report presentation for action by the system’s board of 

directors.

Members of the borrower’s management and staff, including key responsible 

personnel from the operations and maintenance department, and, if appropriate,

consultants should participate in each meeting. Representatives of other 

stakeholder groups should participate as needed. For example, if changes to the 

transmission system are needed, power supplier participation in Meetings 2 and 3 

is essential. If not, it may not be necessary. Since the availability of capital may 

depend on completion of the long range plan, representatives of RUS and other 

lenders if necessary should be invited to attend the meetings and kept informed of 

developments.

While it is often advantageous to conduct the meeting to review the preferred plan

(Meeting 3) in person due to the complexity of the data, maps, and other 
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information to be discussed, it may be acceptable to conduct the meetings by

telephone or web conferences and email exchanges. The increased use of these 

technologies can reduce the cost of the planning process and may enable more 

people to participate.

3 PHASE 1—COLLECT AND EVALUATE SYSTEM DATA

The primary task in Phase 1 is to identify the basic data needed to support the planning 

process and computer model development. It is essential to collect the best available data 

in this process. Steps include identifying data requirements, assigning data collection 

responsibilities and presenting results for discussion at Meeting 1.

Basic system data include, but are not limited to, the following general categories:

• System configuration and operational data;

• Economic parameters and cost estimates;

• Wholesale rates, including any wheeling costs; and 

• Anticipated load growth patterns.

A detailed list of data needed to complete a long-range plan is shown in Exhibit A of this 

Guide.

a System Configuration and Operational Data

Required system configuration and operational data includes:

• Transmission line diagrams, distribution circuit diagrams, and/or computer 

model data reflecting the most current peak-loading conditions experienced;

• Proper feeder wire sizes and number of phases, the location and sizes of 

capacitor and voltage regulator banks, and the correct location of normal line 

opens;

• Accurate peak consumer and substation load data;

• Feeder voltage and current readings at substations and along the electric lines;

• System reliability data; and

• Historical cost data for system improvements and line construction.

Required information about key components of the electric delivery system, 

including transmission and substations, includes:

• Voltages, capacities, and ownership of transmission lines and substations;

• The loading of each substation and available capacity;

• Substation capacity, both firm and spare , if any; and

• The load growth rate for each substation over the last 10 years, if available.

The borrower and its power supplier should discuss their respective plans to 
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determine whether the power supplier has bulk electric plans that could be 

beneficial to the borrower’s distribution system and to avoid duplication of 

efforts. If the power supplier is a generation and transmission cooperative (G&T), 

it is important to determine whether the load is being served on-system directly 

from the G&T’s facilities or off-system through another borrower’s facilities. 

Off-system loads sometimes involve wheeling charges, which should be included 

in the economic analysis. Ownership interests and shared costs of any jointlyowned substations should be identified.

b Economic Parameters

It is necessary to estimate the following economic parameters:

• System annual fixed costs and inflation rates for both energy and construction 

expenses;

• Construction costs for system components, such as transmission lines and 

taps, substations, distribution lines and voltage conversion equipment; and

• Present worth and inflation rates, which should be acceptable to the 

stakeholders.

Costs that are common to all alternate plans under consideration, such as 

consumer distribution transformers, service drops, sectionalizing equipment, 

meters and capacitors, are often ignored in economic comparisons, as they 

typically do not affect the results of the comparison.

c Wholesale Rates

Information about the wholesale energy rate structure of the power supplier and 

any wheeling costs paid by the power supplier for off-system loads should also be 

collected. While this information is sometimes ignored, it can make a significant 

difference in the economic comparison of alternate plans. It is important to 

identify any delivery point costs paid by the distribution system. Such costs are

not necessarily included in a one-ownership1 economic analysis, but they impact 

costs indirectly and should be evaluated.

It is important to determine if there are any anticipated wholesale rate increases or

changes in wholesale rate philosophy that might transfer direct costs from the 

power supplier to the distribution system. For example, a power supplier may 

wish to stop providing subtransmission lines and substations and to transfer the 

ownership and associated costs of these facilities to its wholesale customers. 

While this does not happen often, the borrower should be aware of any potential 

actions that could significantly impact long-range costs.

For example, a power supplier may plan to change from an allocation method of 

 1 See Section 10a for more discussion of one-ownership economic analysis.
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assigning the cost of substation changes to all customers to a method that directly 

assigns the costs of such changes to customers served by the substation. This 

could significantly affect long-range costs and system upgrade decisions.

It is also important to consider territorial laws for the service area being studied. 

Potential annexation of borrower territory by other utilities requires special 

consideration and evaluation.

d Load Forecast

It is essential to begin the long-range planning process with a reasonable and 

supportable load forecast approved by the system’s management, board of 

directors and RUS. Borrowers are typically required to develop a new load 

forecast every two to three years. Borrowers are required to follow the load 

forecast regulations in 7 CFR 1710 subpart E. The forecast should include 

projections of annual kilowatt-hour sales, level and season of annual peak demand 

and losses for a range of assumptions for each district in the borrower’s service 

territory. Many distribution system load forecasts deal with a 10-year period. It 

may be necessary to extend the forecast to cover the planning period, typically 20 

years (see Section 4c and Section 5a of this Guide). Construction projects 

included in the long-range plan should correspond to forecast requirements.

Stakeholders should review the load forecast for reasonableness and to identify 

anomalies or flaws. Any adjustments to the approved forecast should be 

documented and agreed to by the power supplier, borrower and RUS general field 

representative before proceeding. Borrowers should also comply with applicable 

federal and state requirements regarding load forecasts.

The long-range plan should identify three to five key load levels (LLs) to serve as 

benchmarks for construction work plans. Load Level 1 (LL1) is typically the 

actual load level at the beginning of the study, and the final load level is that 

projected for the last year of the study. Interim load levels determine the need to 

construct specific projects. For example, LL1 may correspond to projects 

schedule for the first three years of the long-range plan. LL2 would be the load 

level projected for Year 4, corresponding to projects needed in Years 4, 5, and 6. 

LL3 would be the load level projected for Year 7, corresponding to projects 

needed in Years 7, 8, and 9, and so on. The load levels, not the date, serve as a 

trigger for the construction work plan. If, for example, loads fall short of Load 

Level 2 as predicted for Year 4, construction of projects corresponding to that 

demand may be delayed. If Load Level 3 is reached in Year 5 instead of Year 7, 

certain projects may be constructed earlier. There may be different load levels for 

different parts of the system, and they may trigger construction at different times.
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e System Reliability Data

Reliability is a key issue for all electric suppliers. A thorough review of system 

reliability data is needed to identify weaknesses that can be addressed in the longrange plan and formulate ways to improve system reliability. In general, the

components most likely to significantly affect system reliability are transmission 

lines, substations and distribution feeders. Distribution feeders with smaller 

conductors or feeders that do not serve as ties for substations are likely to 

experience more outage time than larger conductors, looped lines, or ties between 

substations.

The borrower should consider providing on-site backup power for substations that 

serve high-priority loads, such as large towns, hospitals, commercial and 

industrial loads. Designs for distribution feeders should provide strong ties 

between sources for improved reliability. Reliability needs, such as larger 

conductor sizes and overhead versus underground construction, should be 

addressed in the design criteria for the long-range plan.

.

f Operation and Maintenance Survey

RUS requires its field representatives to conduct a periodic review of the 

operations and maintenance practices of each borrower. This review will 

normally be done at least once every three years. The review collects data, such 

as outage information, losses, power factor, capacity factor and other operational 

factors. The results of the review are provided to the borrower on RUS Form 300. 

The review provides a useful overview of the system’s operation and maintenance

characteristics and identifies areas that need to be addressed. It also includes 

suggestions for system improvements.

Projects to be included in the long-range plan will be determined by a number of 

factors, such as costs, including all fixed costs, and the needs identified by the 

operations and maintenance review.

g Conductor Options

Until recently, conductor selection was driven by load current and voltage drop, 

but as energy costs increase, line losses are becoming an increasingly significant 

economic factor. Choosing the correct conductor sizes can help the borrower 

minimize costs. An economic conductor life analysis is a useful tool for 

determining the most economical conductor voltages and sizes for different 

construction options, considering losses, line load levels and voltage drops.

The analysis estimates the total ownership cost of conductors of different sizes 

over their expected life. The information allows the system to weigh the higher 

initial cost of larger conductor sizes against long-term cost savings due to lower 

line losses and lower voltage drops. Other factors considered in selecting a 
RUS Bulletin 1724D-101A

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conductor include:

• Conductor Availability. The borrower should discuss the availability of 

different conductors under consideration with its wire vendors. Suppliers 

should be able to provide the selected conductor during emergencies as well 

as for routine construction.

• Storm Situations. Other systems that could be expected to help restore power

in storm and other emergency situations should have the ability to work on the 

conductor sizes utilized.

• Tooling and Connectors. The borrower should review the cost of the tooling 

and connectors required for the conductors under consideration to determine 

whether any would add significant costs.

• Switching Capability. An economic conductor life analysis provides a 

recommended minimum conductor size, based on the initial load and expected

load growth for a line. However, if main tie lines will be used as backup for 

other feeders, it may be prudent to select a larger conductor size in order to 

improve system reliability.

Conductor options should not be limited to those currently in use on the 

borrower’s system. While ACSR conductors have been utilized extensively by 

electric distribution systems over many years, other available conductors—such 

as AAC, AAAC, and ACAR—should be included in the evaluation. It is 

important to note that the different characteristics of different conductors may 

require different modeling techniques.

Borrowers may find it helpful to find out which conductors other electric systems 

in their area are using and why.

There is typically little cost difference in the pole, pole-top assembly, guying and 

anchoring for conductors of similar strength and size. The primary differences

among conductor options are the cost of the conductor in dollars per 1,000 feet

and the cost of losses.

Exhibit E of this Guide provides an economic conductor life system analysis. 

Additional discussion of the factors involved in such an analysis is included 

in Appendix 1 of this Guide.

4 PHASE 2—DEFINE ENGINEERING AND ECONOMIC CRITERIA

The tasks identified in Phase 1 should be completed before proceeding to Phase 2. The 

information collected is used to establish the basic engineering and economic criteria 

(EEC), or assumptions, for the economic models developed to compare alternate plans 

for meeting future needs.

Exhibit B of this Guide provides an example of engineering and economic criteria. 

Additional details and discussion items identified below are included later in this guide.
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a Basic Cost Estimates and Parameters

The following basic cost estimates and parameters are needed as input to the 

economic models of alternate plans:

• Cost estimates for construction of various distribution lines;

• Cost estimates for 25-kV line reinsulation and conversion, such as step banks

and consumer transformers;

• Cost estimates for uprating existing substations by voltage class and MVA 

capacity;

• Cost estimates for new substation alternatives by voltage class and MVA 

capacity;

• Cost estimates for transmission lines and taps by voltage class;

• Economic parameters for borrower and power supplier, including cost of 

losses, annual fixed charge rate, transmission O&M costs, distribution O&M 

costs, substation O&M costs, avoided energy cost, distribution energy cost, 

inflation rate for energy costs, inflation rate for construction costs, present 

worth rate, delivery point costs and total value of distribution plant;

• Reliability criteria for transmission line looping and substation firm capacity, 

if available;

• Projected system peak loads by load levels from actual load level at the 

beginning of the study to the projected requirements for the final year of the 

study; and

• General criteria for the overall plan, such as distribution system design and 

operating criteria, line and equipment loading limits, and multiphase 

conversion limits.

b Transformer Criteria

It is useful to establish a criteria for replacement of substation transformers, based 

on capacity and age. For example, it is prudent to replace any that have 

significant maintenance problems, have suspect levels of combustible gases or 

show signs of failure. Transformers that have been in service more than 35 years 

are likely to experience major maintenance costs during the planning period. The 

cost of maintaining versus replacing this equipment should be compared in the 

economic analysis.

Several factors should be considered in establishing criteria for sizing 

transformers for substations to ensure that equipment remains in service over its 

useful life, including the initial load and growth rate at the substation location, 

potential load shifts due to new substations and load shifts during emergency 

situations. Areas of the system with low growth rates may require different 

criteria for sizing transformers than areas of the system with higher growth rates.

However, it may be more economical to establish a standard transformer size for 

the entire system to accommodate changes in load growth patterns during the 
RUS Bulletin 1724D-101A

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planning period. There may also be cost benefits to purchasing the same size 

transformer for multiple locations. This provides the flexibility to move units as 

load patterns evolve. Single versus two three-phase transformer configurations 

should be evaluated from a reliability and maintenance perspective.

c Planning Period

Load forecasts normally project loads for a 10-year period. For long-range 

planning purposes, it is usually desirable to predict loads for a longer period. The 

planning period should be at least long enough for the system to need enough 

upgrades and/or new construction to permit the exploration of several alternate

plans and system configurations. In general, this is the amount of time it takes for 

the system load to double, about 20 years at an annual demand growth rate of 

about 3.5 percent and 25 years or more for a system with a 3.0 percent growth 

rate. Planning parameters for systems with growth levels of less than 2 percent 

should be considered on an individual basis.

It is important to choose a period that will stress the electric system to force 

change so that options can be evaluated.

d Design Options

The engineering and economic criteria should establish several design options for 

evaluation. Options for adding capacity, assuming the existing system is 

operating at 12.5 kV or less, include:

• Add no new delivery points, increase the capacity of existing lines and 

substations and maintain the same distribution voltage levels;

• Add no new delivery points, increase the capacity of existing substations 

and convert the distribution voltage to 25-kV operation;

• Add new delivery points and/or increase the capacity of existing 

substations and maintain the same distribution voltage levels; or

• Add new delivery points and convert the distribution voltage to 25 kV.

• Consider a hybrid system with both 12.5kV and 25kV distribution.

The borrower should study the options that best fit system conditions and evaluate 

the economic and operational benefits for each.

e Stakeholder Agreement on Engineering and Economic Criteria

Key stakeholders should have the opportunity to review, discuss, offer comments 

on and agree to the engineering and economic criteria. Meeting 2 provides an 

opportunity for the parties to confer and reach agreement on these issues. 

Agreement on the criteria between the borrower and power supplier is critical to 

the validity of the study.
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5 PHASE 3—DEVELOP DESIGN OPTIONS AND COST ALLOCATIONS

Key stakeholders should agree to the engineering and economic criteria established in 

Phase 2 before proceeding with Phase 3. The next task in the planning process is to 

develop the design options identified in Phase 3 and estimate costs for each option.

a Load Forecast Issues

It is often necessary to extrapolate the system’s approved load forecast to match 

the long-range planning period. One way to do this is to identify different growth 

areas on the system, based on current experience, large loads and expected 

changes. The basic process for this is:

• Identify areas of higher, average and lower growth on the system circuit 

diagram.

• Allocate load and estimate the growth rate in each area based on the total 

system peak demands in the load forecast. 

• Use this information to extrapolate the load forecast to match the planning 

period.

It is also important to determine whether all areas of the system peak during the 

same season. For example, a system that peaks in the summer overall, may serve 

an all-electric subdivision, creating an area within the system that peaks in the 

winter.

Other acceptable methods of load allocation include projecting from individual 

feeders for small systems or using the square mile grid analysis approach. In 

addition, actual individual consumer demand data may be available to systems

that have deployed advanced metering infrastructure (AMI) or a smart meter 

system.

Large power and residential loads are usually forecast separately. One way to 

project large power loads in the 150 to 1,000 kW is to double demand over the 

life of the study. This approach assumes that existing loads will grow and/or new 

loads will be added in the vicinity of existing large power loads.

Large power loads greater 1,000 kW are usually forecast individually, based on 

information provided by the customer. These loads usually do not add significant 

capital requirements, as large commercial customers typically make a contribution 

in aid to construction to pay for any changes to the system needed to service their 

load.

To simplify the system design process, loads are typically assumed to have a 95 to 

98 percent power factor so that designs for alternate system configurations can

omit line capacitors. This reduces design time and costs, and does not 

significantly affect the final economic comparisons. Likewise, sectionalizing and 
RUS Bulletin 1724D-101A

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system protection costs are typically omitted as well. However, the costs for 

capacitors and sectionalizing devices usually are included in the total plant 

projections.

b Distribution System Design and Construction Budget

The next step is to develop a distribution system design and construction budget 

for each alternative under consideration. Appropriate conductors were identified 

in the economic conductor life evaluation (see Section 3g of this Guide). The 

same kVA load capacity should be used for each option so that end-of-line 

accumulated voltage drops are approximately equivalent. For example, if the 25-

kV option has a total drop of approximately 10 volts, then the drop on the 12.5-

kV option should also be approximately 10 volts. This approach provides

comparable service levels for each option, which is necessary for a true economic 

comparison.

The costs associated with each alternative should be calculated for the power 

supplier and borrower using the one-ownership approach (see Exhibit G of this 

Guide). That is, the economic analysis is conducted as if all parts of the delivery 

system, both transmission and distribution, were owned by one entity. This helps 

identify the alternative that will deliver power to the consumer at the most 

economical overall cost, even though different options might require different 

levels of investment by the borrower.

For comparison purposes, line costs are usually levelized over the study period. If 

a borrower has delayed maintaining the system and increasing capacity to the 

point that it is experiencing high voltage drops, the borrower will need to initiate a 

significant construction program as soon as possible to correct the problem. 

Consequently, more capital costs will be incurred in the early years of the study, 

and the levelized cost will be higher than if the same construction program were 

spread evenly over the planning period.

Substation and transmission line capital costs are generally allocated to the year in 

which new capacity is needed. Annual losses, both in primary lines and 

transmission lines, if appropriate, are forecast using an appropriate, calculated 

compound growth rate.

A substation loading chart showing substation capacities and required 

improvements for each alternative under consideration is needed in order to 

properly allocate substation and transmission line costs.

Exhibit F of this Guide provides a sample substation loading chart.

c Reliability Issues

Reliability of service should be evaluated for each alternative. Normally, 
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installing new substations to establish new load centers shortens the distribution 

lines, which should improve reliability. Converting existing distribution lines to a 

higher voltage instead may decrease reliability. The expected reliability of the 

conversion option can be improved by:

• Installing two separate substation power transformers or making provision for 

a mobile substation to increase reliability,

• Establishing main substation tie feeders for transferring load from one 

substation to another,

• Establishing loop-feed transmission to a substation, or

• Employing a more sophisticated distribution line sectionalizing scheme.

Using one or more of these options can help establish comparable reliability for 

options under consideration.

It is important for the economic analysis that the alternatives under consideration 

be based on comparable assumptions. This means that projected load levels 

should be the same for each year, changes in existing substation capacity should 

be scheduled in approximately the same years and voltage drops on circuit 

extremities should be comparable for all alternatives. Close coordination between 

all parties involved in designing the system alternatives and allocating costs is 

essential to ensure that these conditions are met. If alternatives are based on 

different criteria, such as different load levels or different schedules for substation 

capacity increases, the resulting economic analysis will not be sound or valid.

6 PHASE 4—SELECT AND VALIDATE PREFERRED PLAN

The analysis outlined in Phase 3 should be completed before proceeding to Phase 4.

The principal task of Phase 4 is to select and validate the preferred long-range plan based 

on a comparison of the alternative system designs and cost allocations completed in 

Phase 3. The plan selected should not be limited by the existing system. Although there 

are inherent benefits in continuing to use installed facilities, a proposal that requires early 

retirement of those facilities should be adopted if it results in significant cost savings.

a Compare Costs to Determine Preferred Plan

The primary factor in choosing a plan is usually full life-cycle cost. It may be 

necessary to compare a plan with high initial capital costs but low annual costs to

a plan with lower capital costs but high annual costs. A plan chosen just for low 

capital costs or just for low annual costs may not be the plan that provides the best 

service at the most reasonable overall cost to the consumer. There are numerous 

methods of performing this type of economic comparison. Regardless of the 

method used, the following factors should be included in the economic 

evaluation:
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• Time Value of Money, or Present Worth Analysis. Dollars spent this year are 

worth more than dollars spent next year.

• Inflation in Both Energy and Construction Costs. Energy, labor, and material 

costs are likely to increase significantly during the planning period.

• Line Losses. The cost of losses on the distribution system and transmission

lines, if appropriate, should be included in the cost of service.

• Operation and Maintenance Costs. This is usually estimated as a percentage 

of added plant.

• Annual Fixed Charges. This is usually estimated as a percentage of added 

plant.

The present worth method of economic evaluation is preferred in most situations,

but there should be an additional comparison to annual costs to help validate the 

economic results and aid in the selection of the preferred plan.

The preferred plan is usually the option with the lowest one-ownership costs of all 

the alternatives being considered. If two plans have comparable one-ownership 

costs, then the plan that more equitably spreads the capital costs between power 

supplier and distribution system or provides the highest reliability should be

chosen.

Exhibit G of this Guide provides a sample economic analysis workbook,

including a summary list of all plans considered. RUS Bulletin 1724D-104 

provides another example of an engineering economics workbook that could be 

used.

b Perform Sensitivity Analysis to Confirm Preferred Plan

It is important to conduct sensitivity studies for any plans that appear to be 

reasonable in order to verify the results of the economic analysis and selection of 

the preferred plan. This analysis should include variations in key economic 

parameters, including:

• Present worth rate,

• Energy inflation rate,

• Construction inflation rate,

• Fixed charge rate,

• Load growth and

• Wheeling costs, if applicable.

The basic assumptions for these factors should be increased and decreased to 

determine if the preferred plan is still the best choice under different economic 

conditions. It is helpful to present the results of the sensitivity analysis in both 

tabular and graphic form to aid in interpretation and communications.
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Exhibit H of this Guide shows an example of a sensitivity analysis.

If the results of the sensitivity analysis are close, other factors that may be 

considered include:

• Energy Conservation. If one plan results in higher long-term energy savings, 

that plan should be given higher priority.

• Excess Capacity. While each plan must provide the minimum capacity 

required to serve the projected system load, a plan that provides more excess 

capacity at the end of the planning period should be given higher priority.

• Service Reliability. While each plan must provide a minimum level of service 

reliability, a plan that provides better service reliability should be given higher 

priority.

• System Manpower and Labor Costs. The advantage depends on conditions in 

the borrower’s service territory. If there are manpower shortages and labor 

costs are above the national average, the most labor-intensive alternative may 

be less desirable. If labor is readily available in the community, the 

alternative with the larger construction program may be more desirable.

• Flexibility. One plan may provide a greater capability for expansion at the 

end of the planning period while another plan may require radical changes in 

basic design parameters to expand at that point. The plan with the longest 

useful life should be given higher priority. A plan that defers major 

expenditures and provides more flexibility to take advantage of future 

developments in technology should be given higher priority.

• Solution to Chronic Problems. The plan that best addresses a chronic system 

problem should be given higher priority.

A cost-benefit analysis may be helpful in evaluating alternatives based on these

factors.

While economic comparison is the primary basis for selecting the preferred plan, 

the final decision should be based on good engineering judgment and the best

available information. If there is significant uncertainty about a key assumption, 

such as load growth in a specific area, it may be desirable to designate an alternate 

preferred plan. The alternate preferred plan can be included in the planning 

documents and ready for implementation. The final decision on which plan to 

implement can be made once the parameters for the assumption in question have

been firmly established. All work sheets, sketches, maps, and other backup used 

in developing and selecting the preferred plan and the alternate should be included 

in the long-range plan supporting documents and retained for future reference.

c Present Preferred Plan for Review and Acceptance

The final step in Phase 4 is to present the preferred plan and any alternate 

preferred plans to the stakeholders at Meeting 3 for review and acceptance (as 

appropriate). All economic analyses, including any sensitivity analyses, should 
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be presented and fully discussed. The borrower should send summaries of 

preliminary results to stakeholders for their review prior to the meeting.

At the meeting, participants should review and discuss the reasonableness and 

feasibility of the preferred plan and any alternates. If the review reveals any 

serious problems with the analysis or plans, it will be necessary to propose a 

solution, revise the economic analyses and, depending on the extent of the 

revisions, conduct another review. Once the preferred plan is agreeable to all, it 

should be approved by the borrower and power supplier. 

The power supplier should provide written validation of three aspects of the 

study:

• The transmission provider and power supplier were included in the long-range 

planning process.

• The power supplier considers the preferred plan and any alternate preferred 

plan to be reasonable guides for the borrower’s long-term needs in light of the 

power supplier’s system configuration and long-range plans.

• The transmission provider and power supplier will consider the distributor’s 

preferred plan and alternate preferred plan recommendations in their own 

long-range plans.

This letter should be included in the long-range plan report as supporting data.

7 PHASE 5—DEVELOP PLAN FOR IMPLEMENTING LONG-RANGE PLAN

The preferred plan and alternates, if any, provide a vision of the borrower’s system, 

including expected system upgrades, additions and retirements, at a future date. This 

vision is achieved through the construction work plan, which is synchronized with the 

preferred plan through the load levels identified in Phase 1 (see Section 3d of this Guide).

The preferred plan clearly states what needs to be accomplished at each load level in the 

construction work plan and identifies the major components for upgrades and new 

construction. In practice, the construction work plan will likely need to specify 

additional work to complete the configuration in the preferred plan and maintain adequate 

system capacity and acceptable voltage drops.

Ideally, the long-range plan should be completed before the construction work plan. As a 

practical matter, a borrower may need to, with the agreement of the RUS general field 

representative, complete its next construction work plan after completing the long-range 

plan through Phase 4. This allows the borrower to apply for loan funds in a timely 

manner. For example, the construction work plan to meet Load Level 2 would be based 

on the design criteria established by the preferred plan, but the remaining phases of the 

long-range plan would be completed after the construction work plan.
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8 PHASE 6—COMPLETE REPORT AND SYSTEM CIRCUIT DIAGRAMS

It is important to document the long-range planning activities, including analysis and 

results, in a complete written report. Information to be presented in the report includes:

• The engineering analysis of the existing system and the preferred plan;

• Information about alternate preferred plans, if any;

• The strategy for the implementing the preferred plan;

• Summaries of the analysis of options no longer under consideration;

• A discussion of the economic analysis, including methodology and a cost 

comparison of the results for each alternative;

• An explanation of the reasons for recommending the preferred plan;

• Suggestions for standardizing items such as conductor sizes, line reinsulation 

design levels, and substation power transformer sizes and voltages

• Summaries of findings and assumptions to aid the periodic review of the

continued validity of the plan and support the formulation of revisions or 

amendments if necessary; and

• A bibliography identifying all data, external documents and judgment sources.

It is useful to include small sketches of the system or sections of the system to illustrate

or replace written descriptions and to present summaries of basic data, statistics, 

economic comparisons, costs data, and engineering analysis in the form of tables or 

graphs whenever possible.

In addition, the report should include the following tables and diagrams:

• A table showing new construction and major system improvements for 

substations and related transmission line improvements along with the estimated 

costs and expected in-service dates. The table should also include equipment to 

increase the capacity of services, transformers, meters, sectionalizing, regulators, 

capacitors, etc., as well as annual projections of costs for connecting new services.

• A table showing annual cost estimates for ordinary replacements, or new 

equipment that does not result in an increase in capacity or quality of service, that 

result from factors such as normal wear and tear, rot, corrosion and damage.

• A table showing electric plant costs broken down by the categories of new 

services and system improvements. This will enable management to relate 

investment in facilities to the time of installation for use in the preparation of 

long-range financial forecasts.

• A table summarizing key information about the borrower’s electric plant, 

including actual data for the most recent 10 years and projected data for the longrange study period. Information to be tabulated includes number of new services, 

system improvements, system retirements, and peak demands. The data should be 

used to generate accompanying graphs showing total electric plant and total plant 

per peak kilowatt.

• Substation loading charts for each load level, including the percent loading.
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• A circuit diagram for the base, or existing system.

• A circuit diagram for the system as planned at the end of the planning period. 

This diagram should show projected loads along with new construction and

system improvements colored coded for the load level at which the improvements 

are anticipated. The supporting data should include a primary analysis for each 

load level to allow for easy evaluation of system voltage drops and losses. 

Typically, only unregulated voltage drops are included; however, regulated drops 

may be indicated as well if desired or required.

• A transmission line diagram showing all transmission lines crossing the 

borrower’s system, including those owned by the power supplier and other 

transmission providers. The diagram should include all existing substation 

delivery points as well as any new delivery points in the preferred plan and 

alternate plans, if appropriate.

It is not necessary to include the detailed calculations for the engineering analyses and 

other planning investigations in the report. However, this information should be retained 

as reference material. The borrower should retain calculations and work sheets as long as 

the plan is valid and in effect.

The draft report should be presented to appropriate stakeholders for review and comment. 

Any issues raised by the review should be resolved before the report is finalized. The 

final report should be certified by a registered professional engineer licensed to practice 

in the state where the borrower is headquartered.

Exhibit I of this Guide provides a suggested table of contents for a long-range 

engineering plan that can be used as a guide in organizing report contents.

 Form 260 provides a checklist for the long-range plan document. Form 261 provides a 

summary of the long-range plan results, including general data, line miles, substations 

and metering points, and plant investment projects.

A long-range plan is expected to remain valid for seven to 12 years. The final report and 

supporting data should be retained in a manner suitable for long-term use.

9 PHASE 7—PRESENT FINAL REPORT FOR BOARD APPROVAL

The final long-range plan report should be presented to the borrower’s board of directors 

for their review and approval. The presentation should include a discussion of the issues 

associated with electric distribution system planning, the options considered, the results 

of the analysis, and the recommendations for the preferred plan and alternate plans if any. 

It is often helpful to schedule a special meeting for this purpose. Once the review is 

complete and any issues raised resolved, the board of directors should pass a resolution 

approving the plan. The borrower may also need to obtain formal acceptance of the plan 

by their lenders.

Copies of the approved report should be provided to the borrower’s power supplier, and 
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other lenders, if necessary, and state public service commission, if required. If requested, 

supporting documents should also be provided. The borrower should consider providing 

these materials in an electronic rather than printed format.

10 SPECIAL CONSIDERATIONS

a One-Ownership Studies

Most distribution borrowers in the United States do not own transmission lines 

and substations, but the costs for these facilities should be considered in the 

planning process. The one-ownership approach to economic analysis evaluates 

various alternatives as if all transmission and distribution facilities used to deliver 

power to the consumer were owned by one entity. It identifies the plan that has 

the lowest present worth regardless of which entity owns transmission and 

distribution facilities. Only costs paid to outside parties are included in the study. 

Money exchanged between owners of the facilities involved is excluded. It 

should be noted that generation costs are typically evaluated separately from 

transmission and distribution costs and are not included in the one-ownership 

study.

The following example shows a sample analysis of present worth costs of an 

option using the one-ownership concept.

Power Distribution One

Supplier System Ownership

Electric System Cost Summary Costs Costs Costs 

Transmission Line Costs ($TL) $TLPS – $TLPS

Substation Cost ($S) $SPS $SD $SPS+$SD

Distribution Costs ($D) – $DD $DD

Wheeling Charges ($WC) $WC – $WC

Transmission Line Losses ($TLL) $TLL – $TLL

Primary Line Losses @ Distribution Costs ($PLD) $PLD –

Primary Line Losses @ Pwr. Supplier $PLPS – $PLPS

 Total Costs ($TOT) $TOTPS $TOTD $TOT

In this example, transmission line costs, substation costs, distribution costs and 

the cost of primary power supplier losses are costs incurred by either the power 

supplier or the distribution system and thus qualify as one-ownership costs. The 

cost of primary distribution losses and delivery point costs are included wholesale 

rates paid to the power supplier by the distribution system. Therefore, the same 

costs are expenses for the distribution system and a source of revenue for the 

power supplier. To avoid duplication, these costs are subtracted from power 

supplier costs. The economic comparison in Exhibit G also includes oneownership costs.

There are a number of acceptable ways to calculate the costs inputs to a one-
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ownership analysis. It is important for the borrower to work with its power 

supplier to reach agreement on how losses are handled.

b Conversion to a Higher Distribution Voltage

One option for meeting future needs is to convert the distribution system’s 

existing operating voltage to a higher voltage, for example, 4.16 kV to 12.47 kV, 

12.47 kV to 24.9 kV, 12.47 kV or 24.9 kV to 35 kV. Today, most electric 

distribution systems operate at the 12.47 kV level, and conversion to 24.9 kV is 

the most common option considered. It is rare to find distributors operating at

4.16 kV level or 35 kV. However, the economic and operational parameters of all 

options should be considered in evaluating future system needs.

An economical approach to adding system capacity is to raise the primary voltage 

level from 7.2/12.47 kV grounded-wye to 14.4/24.94 kV grounded-wye. This 

reduces the line current by 50 percent, reduces both the total voltage drop on the 

circuit extremities and primary line losses to 25 percent of the 12.47 kV levels, 

and may add to costs.

Conversion to a primary distribution voltage of 25 kV can be the most economical 

approach when transmission lines are not readily available in service areas 

needing additional capacity. This is a good option when it would be necessary to 

construct more than five miles of additional transmission line to support new 

substation and delivery point taps. The higher distribution voltage allows for 

twice the 12.47 kV load and usually supports the use of smaller primary line 

conductors, generally less than 477 kcmil ACSR. The main difference in line 

construction between the two voltage levels is the pin and insulator. However, 

the 125 kV BIL at 14.4 kV distribution transformer costs may be more than the 95 

kV BIL at 7.2 kV units.

Two methods are used in the field for 25-kV conversion. One is conversion by 

phases, using single-voltage consumer transformers. The other is by circuit, using 

dual-voltage, 7.2-kV × 14.4-kV consumer transformers. The first method may be 

less expensive, but the second method may be preferred due to safety and 

reliability considerations. The second method can be accomplished more 

systematically with two- or three-person crews.

Single-phase, platform-mounted autotransformers are no longer recommended for 

use in the primary voltage conversion process as the devices are unreliable for 

high-level through-faults. The best approach to stepping primary voltages—

considering all installation costs—is the use of three-phase pad-mounted 

transformers. The underground residential distribution (URD) method eliminates 

platform mounting costs of units, especially if large two-winding units are used. 

The pad-mounted step transformers are typically two-winding transformer banks

of 5 MVA or less. Lower weight 7.5 MVA and 10 MVA pads are available in the 

autotransformer configuration at a reasonable price.
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The system design for voltage conversions should also be practical and reliable 

for operations. A plan that uses many permanently installed step-down 

transformers is unreliable because system protection and sectionalizing is 

difficult. At 25 kV, it is preferable to convert major services areas, such as 

substations and long feeders, and eliminate the use of step transformers for long 

taps with many distribution transformers.

The use of step transformers for long periods of time should be avoided if 

possible. They can be useful during the conversion process but generally should 

not be used in permanent installations. An exception is the installation of step 

transformers at key tie points where the distribution voltage changes. In this case, 

they are in place for use in emergencies and load transfers, and typically do not 

carry load. Step transformers may also be needed in underground distribution 

systems.

With this approach, losses from step transformers can be ignored and the number 

of step banks for the conversion process can be greatly reduced.

Operating at the higher distribution level of 25 kV has advantages and 

disadvantages. Advantages cited include:

• Reinsulating and converting the distribution system can revitalize an old 

system and eliminate old equipment that has caused problems;

• The amount of overloaded lines may be reduced;

• Excessive voltage drops may be eliminated;

• It may reduce the need for line voltage regulators, a high-maintenance and 

high failure rate device; and

• It can reduce system losses by two to three percent.

Disadvantages cited include:

• The system may experience more feeder outages than at the lower voltage,

because the higher voltage will fault to ground through tree branches, whereas 

the lower voltage system will burn the branches and trees;

• More consumers are served on a given feeder, so outages have a greater 

impact on system reliability; and

• Operating expenses are higher for systems using both 12.5-kV and 25-kV 

equipment.

Operating a 25-kV system requires more aggressive right-of-way maintenance 

than a lower voltage system to reduce and avoid outages caused by vegetation.

Since a 25-kV system serves more consumers per substation, per feeder and per 

tap, it may require additional consideration to sectionalizing capabilities and 

reliability issues.
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Converting to 25 kV does not provide an economic advantage for every system. 

Systems with extensive transmission lines in their service areas and reasonable 

substation construction costs may find it difficult to justify the conversion. 

Systems experiencing growth of less than two percent per year will also find it 

difficult to justify the conversion on an economic basis. In some cases, it may be 

desirable to insulate for 25 kV at an early date in preparation for full conversion at 

a later date, such as when an older system needs to be essentially rebuilt or when 

part of a system is already operating at 25 kV. The added costs for the higher 

insulation level are low and may provide significant benefits in the future.

RUS Bulletin 1724D-105, “Rural Distribution System Conversion 

Considerations,” provides additional information on system conversions.

c Transmission Line Losses

Transmission losses can be a factor when considering conversion from one 

transmission line voltage to another, but in most cases transmission losses are 

common between plans and can be ignored. The power supplier can provide 

guidance as to whether or not to evaluate transmission losses in the long-range 

system study.

When an alternate plan transfers load from one transmission line to another, it 

may be necessary to consider transmission losses. Moving load served on a 

heavily loaded transmission line to a lightly loaded transmission line or from a 

high-impedance transmission line to a low-impedance transmission line may 

reduce transmission losses enough to make one alternative more attractive than 

another. Shifting load in the opposite direction may reduce an alternative’s 

feasibility, particularly if the load being moved is a significant portion of the 

rating of the line.

When plans involve conversion or elimination of subtransmission lines with 

voltages ≤ 69 kV, it is prudent to calculate the transmission line losses at the oneownership level. Subtransmission line losses can be significant, especially when 

lines are close to overload and carry load factor loads greater than 45 percent for 

distances of more than 20 miles.

d Radial Transmission Line Reliability Assessment

The long-range plan should address the reliability of delivery points, especially 

those served by long, highly loaded radial transmission lines. While this is often

considered the power supplier’s responsibility, from a reliability standpoint it is 

desirable to view the electric system as a total unit. The power supplier and 

distribution system should jointly plan for delivery points in order to improve 

system operations and reliability.

Appendix 2 of this Guide outlines a procedure for assessing radial transmission 
RUS Bulletin 1724D-101A

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lines.

e Long-Range Capital Expenditures for Slow-Growing and Aging Systems

While long-range planning typically focuses on meeting needs resulting from 

system growth, other issues must sometimes be addressed. For example, 

borrowers with older systems may need to replace aging plant before system 

reliability falls to unacceptable levels. Systems experiencing slow or declining 

growth may need to plan for retirement of existing plant.

Such conditions and their capital needs should be addressed in the long-range 

plan. A systematic evaluation will help determine which replacement alternatives 

provide the most benefits based on system operating conditions, capital costs,

electric rates, reliability and the ability to get the work accomplished in a timely 

manner.

Appendix 3 of this Guide provides additional information about this process.

f Use of Distributed Generation and Smart-Grid Technology

Borrowers should be aware of the potential impact of emerging energy policies 

and initiatives on the planning process. Distributed generation (DG) has the 

potential to impact long-range planning in the electric utility industry. Significant 

growth in the use of distributed resources was predicted in the 1990s in 

anticipation of deregulation and new opportunities for competition. Deregulation 

has not been adopted as then expected. There were, however, some successful 

deployments, which provided practical experience and successful proofs of 

concept.

Today, global environmental concerns and the expectation of significantly 

increased energy costs in the future are creating pressure to adopt energy policies 

that will significantly impact the electric utility industry. Initiatives that support 

increased deployment of distributed generation, the development of renewable 

energy sources, both centralized and distributed, higher energy-efficiency 

standards, demand-side management, and similar smart grid applications have the 

potential to radically change the way electricity is provided to the consumer.

The goals of current energy policy include increasing efficiency, reducing

demand or, at a minimum, reducing the rate of growth, and increasing reliance on 

domestic resources. If these goals are achieved, there will be new design criteria

and a shift in emphasis from system performance to system maintenance and the 

sustainability of existing infrastructure. Although the impact is hard to quantify at 

this point, new policies will ultimately affect planning and operations for all 

aspects of the electric system—generation, transmission, and distribution.

Proponents of smart grid technology envision an array of active demand-side 
RUS Bulletin 1724D-101A

Page 30

management methods that depend upon both programs with predictable energy 

savings, such as active load management systems and appliances, and applications 

with unpredictable results, such as real-time pricing and inclining block rate 

structures. It remains to be seen how much these systems will influence longrange load forecasts and the planning process. Although there is increasing 

pressure to reduce both capital expenditures and energy consumption, borrowers

must ensure that the electrical network operates to certain standards under all 

conditions.

If there is a proliferation of distributed generation, future planning activities may 

have to address issues such as automation and control, communications, 

computing systems, and electronic security. While these concepts are likely 

several years from materially affecting distribution system long-range planning 

practices, it is important to be aware of the potential impact and monitor 

developments.

Appendix 4 of this Guide provides detailed information about distributed 

generation applications in four categories—large-scale, medium-scale, smallscale, and residential/commercial solar photovoltaics (PV)—and discusses ways 

to include them in a system’s long-range plan.

g Special Equipment Considerations

Electric distribution systems should evolve as new technology to improve system 

operations, reliability and efficiency becomes available. However, the long-range 

study is not the appropriate tool for analyzing new technology. Separate studies 

are needed to evaluate the capabilities of new equipment to improve system 

operations, reliability and efficiency, such as:

• Automated metering reading (AMR),

• Electronic and/or microprocessor relays and metering,

• Geographical information systems (GIS),

• Supervisory control and data acquisition (SCADA),

• Concrete and steel poles,

• Communication systems,

• Special sectionalizing equipment,

• Outage management systems,

• Computer software,

• Operational tools and

• Other smart grid technologies.

11 USE OF THE LONG-RANGE PLAN TO GUIDE SYSTEM CHANGES

When complete, the long-range plan provides a picture of the future electric system. It 

specifies line conductor sizes, primary voltages, and new delivery point locations;
RUS Bulletin 1724D-101A

Page 31

addresses transmission needs; and provides a basis for the distribution system and power 

supplier to make sound decisions to satisfy long-range system needs.

The plan allows the borrower to evaluate proposed sites for future substations and 

transmission lines and to purchase right-of-way in advance if state statutes and corporate 

by-laws allow. This can result in significant cost savings, especially in high-growth 

areas.

It is important to review the plan any time major changes in the electric system are under 

consideration, particularly when developing construction work plans or acquiring new 

large loads.

The benefits gained from the planning process and implementation of the long-range plan 

will offset the costs of developing the plan and reduce the likelihood of the need for 

costly rebuilds.

12 POWER SUPPLY STUDIES

The economic analysis in the long-range plan and the selection of the preferred plan are 

based on estimated parameters for component costs and system fixed charges. It is 

necessary to conduct a power supply study (PSS) to develop specific, accurate cost 

estimates and to determine availability of land, including right-of-way, before a particular 

project can be included in the budget and construction can begin. Most power suppliers, 

including generation and transmission cooperatives, provide guidelines for conducting 

such studies before capital is committed for construction. The studies follow most of the 

same procedures and guidelines used in the long-range system study but are based on

more accurate costs determined from actual design options and field reviews. In 

addition, a power supply study is limited to a small part of the overall electric system.

Sometimes the power supply study results in a conclusion and system approach that is 

different from the long-range plan. In this case, the power supply study should be 

adopted as an amendment to the long-range plan. If the results of power supply studies

are frequently different from the long-range plan, it may indicate that it is time to develop 

a new plan.

13 PERIODIC DETERMINATION OF PLAN VALIDITY

A borrower should review its long-range plan on a regular basis by comparing basic data, 

design criteria, and assumptions with actual system experience in order to verify the 

plan’s continued validity. At a minimum, a system should review its plan prior to 

preparing a new construction work plan, and a faster-growing system should conduct an 

annual review. If actual experience deviates significantly from assumptions, it is time to 

devise a new plan.

The average life span of a long-range plan for a fast-growing system is five to seven

years, seven to 10 years for a moderate-growth system, and 10 to 15 years for slow-
RUS Bulletin 1724D-101A

Page 32

growth systems. Regular review will ensure the plan remains valid and will also assist 

the borrower in determining the need for a new plan when revisions are no longer 

adequate. Events that necessitate revision or replacement of the long range plan include:

• Loads develop faster or slower than projected.

• Power suppliers change their plans and service policies.

• Transmission or substation additions which are not in the long-range plan are needed.

• Significant large loads are added to the system.

• Necessary rights-of-way cannot be obtained.

• Laws and/or ordinances, such as requirements for underground line construction, 

change.

• Changes in technology offer new benefits.

Even if no major changes are needed, numerous minor revisions may necessitate a new 

plan.

14 CONCLUSION

Every borrower should develop and periodically review a long-range plan for meeting the 

system’s future needs. The borrower should create the plan through a structured process 

that includes consultation and coordination with key stakeholders, including its power 

supplier, and its lenders if appropriate.

The long-range plan estimates the systems future needs based on its approved load 

forecast, evaluates alternate plans for meeting those needs, identifies the preferred plan 

and alternate plans if needed based on cost and other considerations, and proposes a 

schedule for system upgrades, new construction and retirements to implement the plan.

Users of this guide are encouraged to look at additional supplemental documents which 

are Excel® 2010 Workbooks. They can be useful tools in the completion of a LongRange System Study. A summary of those documents is given below:

1. LRPG Exhibit C, Fixed Charges Calculations;

2. LRPG Exhibit D, Radial Transmission Line Assessment;

3. LRPG Exhibit E, Conductor Life Analysis;

4. LRPG Exhibit G, Economic Plan Analyses;

5. LRPG Exhibit H, Sensitivity Analyses;

6. LRPG Exhibit K, RUS Long Range Plan Report Checklist (Form 260); and

7. LRPG Exhibit L, RUS Long Range Plan Report Summary (Form 261).

Documents 1–5 each have a “Use Narrative” explaining the use of the workbook and how 

the spreadsheet can be applied. Copies of the documents are included on the RUS 

website.
RUS Bulletin 1724D-101A

Exhibit A

Page 1

EXHIBIT A

SUMMARY OF DATA REQUIRED

The information listed below is considered to be the typical data needed by the distribution

planner to complete a Long-Range Plan (LRP).

1. 10 years of year-end RUS Financial and Operating Report Electric Distribution (Formerly 

known as the Form 7).

2. System computer model data and system maps for base system conditions that are available.

3. GIS mapping system for peak load conditions, if available.

4. A copy of the most recently completed Operations and Maintenance Survey (RUS Form 

300).

5. Loading conditions by line section for the most recent peak month conditions.

6. Historical growth factors for consumers, kWh usage, and kW demand.

7. Other peak system load data, including measured monthly peak substation loading and feeder 

peak currents from field ammeters or SCADA system datum.

8. Historical annual fixed rate charge for the past five years, at a minimum, using the fixed 

charge spreadsheet of this LRPG.

9. Annual fixed rate charges of the power supplier.

10. A current copy of Load Forecast, formerly called the Power Requirements Study.

11. System Engineering and Economic Criteria (update as required).

12. Current substation configurations, voltages, capacities, ownership, age, conditions, power 

transformer losses, expansion capabilities and limitations, etc.

13. The current system policy for primary conductor size use and why they were chosen.

14. The average costs of building the various size distribution lines on a dollar-per-mile basis in 

today’s dollars.

15. The average costs of building the various size and voltage class transmission lines.†

16. The average costs of building various size and voltage class substations.†

17. The average costs of building various size low-side switching structures on a per-bay basis.

18. A list of special, on-system, large power and growth loads, getting input from district 

managers (be sure to document those loads that are in the current LF and those that are not).

19. Current electric state territorial laws and the possibility for system annexation by a 

neighboring distributor.

20. Wholesale rate structures and special conditions, including any anticipated changes. Also 

identify inflation rate for wholesale power costs and determine current avoided costs in 

dollars per kilowatt-hour.†

21. Transmission line locations within the electric distributor’s service area, their conductor size 

and voltage class. Also identify potential substation sites by locating industrial parks and 

potential large power and residential growth areas.†

22. Employment and income sources, growth potentials, land terrain and uses, saturation areas, 

inflation rates, etc.

23. Determine how many copies of the LRP report will be needed, including a bound copy of the 

supporting data.

† May have to be provided by power supplier.
RUS Bulletin 1724D-101A

Exhibit B

Page 1

EXHIBIT B

SAMPLE ENGINEERING AND ECONOMIC CRITERIA

ABC ELECTRIC COOPERATIVE

City, State

2008 LONG-RANGE PLAN

ECONOMIC CRITERIA

(2007 DOLLARS)

DISTRIBUTION COST

ESTIMATES (Distributor) Cost/Mile

1ø 1/0 ACSR = $20,000 per mile

2ø 1/0 ACSR = $35,000 per mile

3ø 1/0 ACSR = $42,000 per mile

3ø 3/0 ACSR = $54,000 per mile

3ø 336 ACSR = $65,000 per mile

3ø 336 ACSR Double Circuit = $92,000 per mile

3ø 477 ACSR = $70,000 per mile

3ø 477 ACSR Double Circuit = $105,000 per mile

3ø 795 ACSR = $121,000 per mile

1ø 1/0 AL URD = $80,000 per mile

1ø 4/0 AL URD = $85,000 per mile

3ø 1/0 AL URD = $150,000 per mile

3ø 4/0 AL URD = $175,000 per mile

3ø 350 AL URD = $180,000 per mile

3ø 500 AL URD = $185,000 per mile

3ø 1000 AL URD = $190,000 per mile

3ø 1500 AL URD = $200,000 per mile

1ø 25kV Reinsulation = $5,100 per mile

2ø 25kV Reinsulation = $5,900 per mile

3ø 25kV Reinsulation = $8,200 per mile

1ø 500 kVA Step Transformers (Pad) = $15,000 each

3ø 3000 kVA Step Transformers (Pad) = $86,000 each

3ø 5000 kVA Step Transformers (Pad) = $120,000 each

14.4-kV Transformer Replacement Cost = $750 each

Transformer Change-Out Labor Costs = $300 each

SUBSTATION COST ESTIMATES

3ø Circuit Breaker or Recloser for Substation = $22,000 per feeder
RUS Bulletin 1724D-101A

Exhibit B

Page 2

ABC ELECTRIC COOPERATIVE

City, State

2008 LONG-RANGE PLAN

ECONOMIC CRITERIA

(2007 DOLLARS)

SUBSTATION COST ESTIMATES*1

CURRENT PROJECTS*2

Transformer # Feeder

Description ___Size___ __Bays_ Cost Comments

Uprate existing 46kV/12.5kV 

Substation A to 115kV/12.5kV 12/16/20 MVA 4 $1,200,000 TBC in 2008

Abandon existing 46kV/12.5kV Substation 

B and build new 115kV/12.5kV sub 12/16/20 MVA 4 $1,200,000 TBC in 2008

Build new 115kV/25kV Substation C 12/16/20 MVA 4 $1,200,000 TBC in 2008

EXISTING SUBSTATIONS

Power Transformers Existing Proposed

Description Transformer Size Transformer Size Cost Comments

Uprate existing transformer at Substation D 10/12.5 MVA 12/16/20 MVA $700,000

Uprate existing transformer at Substation E 10 MVA 12/16/20 MVA $1,400,000

Uprate existing transformer at Substation F 10/12.5 MVA 12/16/20 MVA $700,000

Uprate existing Substation C 1-10/16/20 MVA 2-12/16/20 MVA $1,000,000

Uprate existing Substation E 1-10/16/20 MVA 2-12/16/20 MVA $1,200,000

25 kV Conversion

Description Cost Comments

Uprate existing Substation D

from 115kV/12.5kV to 115kV/25kV $650,000

Uprate existing Substation E

from 115kV/12.5kV to 115kV/25kV*3 $650,000

Uprate new Substation H

from 115kV/12.5kV to 115kV/25kV $700,000

NEW SUBSTATIONS

Transformer # Feeder

Description ___Size___ __Bays_ Cost Comments

Build new 115kV/12.5kV sub 10/12.5 MVA 4 $1,400,000

Build new 115kV/12.5kV sub 10/12.5 MVA 6 $1,472,000

Build new 115kV/25kV sub 10/12.5 MVA 4 $1,425,000

Build new 115kV/25kV sub 10/12.5 MVA 6 $1,497,000

Build new 115kV/12.5kV sub 12/16/20 MVA 4 $1,450,000

Build new 115kV/12.5kV sub 12/16/20 MVA 6 $1,522,000

Build new 115kV/25kV sub 12/16/20 MVA 4 $1,475,000

Build new 115kV/25kV sub 12/16/20 MVA 6 $1,547,000

*1 Data provided by G&T *2 2007 Dollars *3 Credit of $169, 289 (per G&T) for existing power transformer at Substation E not included in cost estimate

TBC=To Be Completed

NOTE: G&T would install a 2nd 20 MVA transformer in lieu of a 15/20/25 MVA unit.
RUS Bulletin 1724D-101A

Exhibit B

Page 3

ABC ELECTRIC COOPERATIVE

City, State

2008 LONG-RANGE PLAN

ECONOMIC CRITERIA

(2007 DOLLARS)

TRANSMISSION COST ESTIMATES*1

115 kV Tap Point = $250,000

115 kV Transmission Line Cost per Mile = $350,000

115 kV Transmission Line (For Substation E)—0.7 mi. = $245,000

115 kV Transmission Line (Substation C to Substation F)—5 mi. = $1,750,000

115 kV Transmission Line (Substation D to Substation H)—3.75 mi. = $1,312,500

*1 Per G&T estimates

ECONOMIC and BASE ASSUMPTIONS

(2007 BASIS)

Power Distributor Power Supplier*

Elec. Coop. Name G&T Name

Distribution Sub. / Trans.

Losses/kWh ($) $0.0600 $0.0400

Present Worth Interest Rate (%) 6.00% 6.00%

Annual Fixed Charge (%)** 9.83% 10.50%

T&D O&M Costs (%) 6.23% 0.00%

Substation O&M Costs (%) 0.00% 0.00%

Inflation Rate (%) 3.50% 3.50%

Energy Inflation Rate (%) 6.00% 2.88%

Annual Delivery Point Charge ($) – –

Total Value of Distribution Plant (12/31/xx) $70,123,456

* Data provided by G&T

** Interest, depreciation, taxes, and insurance only.

SYSTEM DESIGN CRITERIA

Each alternative being evaluated will be designed utilizing the Engineering and Economic 

Criteria (EEC) from the most current Construction Work Plan. Each long-range plan will be 

designed to have approximately the same capacity by requiring that line regulators will not be 

required in the long-range load level, but will allow for one bank of line regulators when and if 

needed on interim load levels.
RUS Bulletin 1724D-101A

Exhibit B

Page 4

ABC ELECTRIC COOPERATIVE

City, State

2008 LONG-RANGE PLAN

ECONOMIC CRITERIA

LOADING AND OPTIONS

LOADING LEVELS*1

Most Probable

Load Summer Peak Winter Peak Total

Levels Years kW Demand kW Demand Consumers

1 2006 (05/06) System (actual) = 97,848 113,139 27,263

2 2011 (10/11) System = 127,552 144,271 30,227

3 2015 (14/15) System = 137,846 155,914 32,360

4 2026 (25/26) System = 163,370 184,785 37,819

2006 to 2026 Average Compound Growth Rate = 2.60% 2.48% 1.65% per year

Extreme Weather

Load Summer Peak Winter Peak Total

Levels Years kW Demand*2 kW Demand Consumers

1 2006 (05/06) System (actual) = 97,848 113,139 27,263

2 2011 (10/11) System = 144,797 175,874 30,227

3 2015 (14/15) System = 157,398 191,519 32,360

4 2026 (25/26) System = 188,647 230,314 37,819

2006 to 2026 Average Compound Growth Rate = 3.34% 3.62% 1.65% per year

*1 From 2007 Load Forecast *2 Recommended load levels for Long-Range System Study

PLAN OPTIONS CONSIDERED*3

Plan A No New Delivery Points Added and Distribution Lines to Remain at Current 

Voltage Levels

Plan B No New Delivery Points Added and All Distribution Voltage Converted to 25 kV

Plan C New Delivery Points Added and Distribution Lines Remain at Current Voltage 

Levels

Plan D New Delivery Points Added and Distribution Voltage Converted to 25 kV

Plan D1 Like D, but Substation B added instead of Substation A

Plan D1A Like D1, but Substation C served from G&T 115-kV transmission line.

*3 As decided by the cooperative, the power supplier, and/or RUS, as the case may be
RUS Bulletin 1724D-101A

Exhibit C

Page 1

EXHIBIT C

RUS FIXED CHARGE RATE CALCULATION GUIDE

ABC ELECTRIC COOPERATIVE

City, State

LONG-RANGE PLAN

Following is some data to assist in the calculation of a Fixed Charge Rate. A fixed charge rate is 

composed of several factors: the costs of capital, operation and maintenance, taxes, insurance,

and depreciation. Calculating the cost of insurance as a percentage of investment is difficult and 

the result makes little difference; therefore, it can be ignored for most applications. The fixed 

charge rate is not an exact figure, but an estimate which is dependent on the quality of the 

assumptions involved in its calculation.

Note: References to annual Financial and Operating Report Electric Distribution are based on 

the 2014 Revision of the report.

I. Cost of Capital

A. It is important to recognize the cost of capital, which is greater than the cost of debt. 

This is because there is a cost of member equity. The return on equity portion of this 

calculation can be figured in at least three ways. The Goodwin method includes the 

cycle of capital credits in calculating the return on equity. Or, one may adopt a return 

on equity that a state regulatory authority has declared to be adequate for electric 

utilities. Or a TIER-based calculation, such as that illustrated below, may be used.

B. Net TIER (Times Interest Earnings Ratio)

1. For future projects, TIER should be selected in accordance with the owner’s Equity 

Management Plan.

2. For comparison, TIER for a past year could be calculated from data on the annual 

Form 7:

TIER = Interest [Part A, line 15(b)] + Margins [Part A, line 28(b)] = $1,892,504 + $1,625,723 = 1.859

 Interest [Part A, line 15(b)] $1,892,504

C. CAPITAL STRUCTURE

1. For future projects, the debt ratio should be in accordance with the owner’s Equity 

Management Plan. Line of credit or short-term borrowing should be taken into

consideration in long-term financial decisions.

2. For comparison, the debt and equity ratios for a past year could be calculated from 

data on the annual Form 7:

Debt Ratio = LTD (Part C,line 41) = $36,131,862 × 100 = 50.79%

 LTD (Part C,line 41) + Tot. Marg. & Eq. (Part C,line 36) $36,131,862 + $35,001,345

Equity Ratio = Tot. Marg. & Eq. (Part C,line36) = $35,001,345 × 100 = 49.21%

 LTD (Part C,line 41) + Tot. Marg. & Eq. (Part C,line 36) $36,131,862 + $35,001,345
RUS Bulletin 1724D-101A

Exhibit C

Page 2

D. COST OF CAPITAL

1. For future projects the cost of debt should be estimated carefully, taking long-term 

trends into account. A suggested form would be:

Proportion Long Range Est.

 of Debt of Interest Rate

RUS 70% × 4.60% = 3.22% (a)

Supplemental Lender 30% × 6.00% = 1.80% (b)

Cost of Debt = (a) + (b) = 5.02%

2. In case one needs to calculate the embedded cost of debt for a past year, it can be 

calculated from the annual Form 7:

[Embedded cost of debt] Interest [Part A, line 15(b)] × 100 = $1,892,504 × 100 = 5.24%

 LTD [Part C, line 41] $36,131,862

3. Weighted cost rate of debt: Debt Ratio Cost of Debt

(from 1.C above) (from 1.D above)

50.79 × 5.02 = 2.55% (CD)

4. Weighted cost of equity: Equity Ratio Cost of Debt

(from 1.C above) (from 1.D above)

49.21 × 5.02 = 2.47 % (CE)

5. Cost of capital: Wtd. cost rate of Debt TIER

(from 1.D.3 above) (from 1.B above)

2.55 × 1.86 = 4.74 % (CC)

II. Operation and Maintenance

A. For future projects, O&M should be selected to agree with the various plan alternatives. 

If a more costly alternative promises lower O&M, it should be reflected here.

B. For comparison, a historic distribution-plant O&M could be calculated by this form, 

with figures from the annual form 7:

Part E Part F

line 15(e) line 7(a)

Net Distribution Plant, annual Form 7, last year $66,382,036 – $ = $66,382,036

Net Distribution Plant, annual Form 7, 2 years ago $63,359,785 – $ = $63,359,785

Average Net Distribution Plant last year = $64,870,911 (a)

Distribution Operations: Part A, line 5(b): = $ 2,636,701 (b)

Distribution Maintenance: Part A, line 6(b): = $ 2,072,182 (c)

O&M as % of Avg. Net Dist. Plant [(b) + (c)] / (a) × 100;

or estimated from II.A., above $4,708,883 7.26% (O&M)

III. Taxes

Property tax: annual Form 7, last year, Part A, line 13(b) $ —

Other tax: annual Form7, last year, Part A, line 14(b) $ 4,653

Total taxes paid on plant $ 4,653 (a)

Plant the taxes were paid on: Net Utility Plant, annual Form 7, 2 years ago, Part C, line 5 $ 54,849,072

 + Materials and Supplies, annual Form 7, 2 years ago, Part C, line 22 $ 847,091

$ 55,696,163 (b) 0.0084 % (Tx)

Tax Rate: [(a)/(b)] x 100, or estimated future tax rate
RUS Bulletin 1724D-101A

Exhibit C

Page 3

IV. Depreciation

Use an appropriate depreciation figure for the projected alternative(s) being studied. Most owners use straight-line 

depreciation where the depreciation rate is the reciprocal of the asset’s life.

Annual rate for the coop, for plant or for classes of plant 3.24% (Dep)

V. Total Annual Fixed Charge Rate

= Cost of Capital (CC) + Oper. & Main. (O&M) + Taxes (Tx) + Depreciation (Dep) = 15.25%

VI. Modified Tier (Net TIER less G&T Capital Credits)

Modifed TIER = Interest [Part A, line 15(b)] + Margins [Part A, line 28(b)] - G&T CC [Part A, line 25(b)]

 Interest [Part A, line 15(b)]

= $1,892,504 + $1,625,723 – $833,883 = 1.4184

 $1,892,504

VII. Debt Service Coverage (DSC) Ratio

DSC = Interest [Part A, line 15(b)] + Margins [Part A, line 28(b)] + Dep. [Part A, line12 (b)]

 Total Debt Service = Principal [Part O, line 13(c)] + Interest [Part A, line 15(b)]

= $1,892,504 + $1,625,723 + $2,387,846 = 1.85

 $1,307,936 + $1,892,504

VIII.Modified Debt Service Coverage (DSC) Ratio

Modified DSC =

Interest [Part A, line 15(b)] + Margins [Part A, line 28(b)] + Dep. [Part A, line 12(b)] – G&T CC [Part A, line 25(b)]

Debt Service [Part O, line 13(c)] + [Part A, line 15(b)]

= $1,892,504 + $1,625,723 + $2,387,846 – $833,883 = 1.58

 $1,307,936 + $1,892,504

IX. Plant Revenue Ratio (PRR)

PRR = Total Utility Plant [Part C, line 3] = $79,937,007 = 5.45

 Elec. Revenue [Part R, line 12+13] – Power Cost [Part L, line 5(d)] $43,400,629 – $28,742,748
RUS Bulletin 1724D-101A

Exhibit C

Page 4

ABC ELECTRIC COOPERATIVE

City, State

SUMMARY RUS FIXED CHARGE RATE PROJECTIONS

TOTAL ANNUAL FIXED CHARGE RATE

Cost Cost Operation

Debt Capital Maintenance Taxes Depreciation

Year (CD) TIER (CC) (O&M) (Tx) (Dep) (TFCR)

2002 2.24% × 2.6218 = 5.87% 6.39% 0.00% 3.24% 15.50%

2003 2.49% × 2.2376 = 5.57% 6.08% 0.00% 3.24% 14.88%

2004 2.59% × 1.6704 = 4.32% 6.21% 0.00% 3.24% 13.77%

2005 2.58% × 2.0150 = 5.20% 6.44% 0.00% 3.24% 14.87%

2006 2.55% × 1.8590 = 4.74% 7.26% 0.01% 3.24% 15.25%

Projected 2.49% 2.0808 5.14% 6.48% 0.00% 3.24% 14.86%

TFCR = Cost of Capital (CC) + Oper. & Main. (O&M) + Taxes (Tx) + Depreciation (Dep)

KEY RATIOS

Plant

Modified Debt Equity Modified Revenue

Year TIER TIER Ratio Ratio DSC DSC Ratio

2002 2.62 2.43 44.57% 55.43% 2.48 2.36 5.22

2003 2.24 1.94 49.57% 50.43% 2.10 1.93 5.25

2004 1.67 1.50 51.53% 48.47% 1.75 1.65 5.66

2005 2.02 1.72 51.40% 48.60% 1.94 1.76 5.39

2006 1.86 1.42 50.79% 49.21% 1.85 1.58 5.45

Projected 2.08 1.80 49.57% 50.43% 2.02 1.86 5.40
RUS Bulletin 1724D-101A

Exhibit D

Page 1

EXHIBIT D

RADIAL TRANSMISSION LINE RELIABILITY AND OPERATIONAL ASSESSMENT

Radial Transmission Line (RTL) Characteristics: RTL #: ABC25

Name and Description: Southport to Wewa 115 kV

Operating Voltage (kV): 115 Conductor Size & Type: 397ACSR (Ibis)

Right-of-Way Width (feet): 100 Radial Distance (miles): 33.5

Last Peak Load (MW): 18.7 Peak Time (month, year): Jul-09

Load Distance Service Factor (MW-Miles):A 626 Year Built: 1985

With loss of the RTL, what % of load can existing distribution ties support? None

Major Line Maintenance Cycle Years: 15

Year of Last Major Line Maintenance: 2002

Right-of-Way Location (cross-country, roadside, etc.): Cross Country; Swamp; Water

Right-of-Way Maintenance Cycles (years): 5

Frequency of Right-of-Way (years):

Inspections Annually Mowing/Spraying 5

Danger Tree Removal As Required Side Trimming 10

Transmission Line Provider: ABC G&T

Impacted Distributors or Cooperatives: XYZ Cooperative Only

RTL Reliability and Operational QuestionsB No Yes

1. Does the RTL have a high Load Distance Service Factor (LDSF) greater than 150 

megawatt-miles? X

2. Is the RTL poorly accessible as determined by the Owner during all or part of the 

year? X

3. Does the RTL serve a delivery point that provides power to high priority loads (e.g., 

hospitals, manufacturing parks, airports, commercial loads, etc.)? X

4. Is the conductor in deteriorated condition based on recent sample testing? X

5. Is the RTL condition contributed to more than three sustained outages over the last 

two years? X

6. Has there been an outage over four hours in the past five years attributed to the RTL 

(excluding those during a major storm)? X

7. Is the RTL in the power supplier’s top 5% of most unreliable lines? X

8. Does the RTL owner have any major improvement plans in the near future or in the 

general area of the distributor/cooperative substation? X

9. Is the RTL operating at 69 kV or less and have a >50% of the conductor published 

full load amperes for the projected long-range peak loading conditions? X

Number “Yes” ResponsesC = 6

RTL PLANNING COMMITMENT

Based on the above assessment, the electric system distribution engineer has decided that the referenced

RTL X is or is not to be included in the new electric system long-range plan. A copy of 

this assessment and commitment is to be supplied to the RTL provider indicated above.

Signature:

Distributor’s Planning Engineer Name: Alfred E. Newman, P.E.

Distributor’s Planning Engineer Title: Manager of E&O, XYZ Cooperative

A Load Distance Service Factor = (Latest Peak Demand Load Served) × (Radial Line Distance) B Categories shown in italics are to be answered by the RTL Owner and Provider, if applicable. C RTLs that have a number of “affirmative” responses to the reliability and operational questions above should be included in the long-range 

planning process.
RUS Bulletin 1724D-101A

Exhibit E

Page 1

EXHIBIT E

SAMPLE ECONOMIC CONDUCTOR LIFE SYSTEM ANALYSIS

ABC ELECTRIC COOPERATIVE

CITY, STATE

2008 LONG-RANGE PLAN

CONDUCTOR LIFE CYCLE ANALYSIS

(NEW CONSTRUCTION LEGEND AND INPUT VALUES)

0.00% TOTAL Total fixed cost. This is an optional replacement for O&M + TAX + DEP + INS.

6.23% O&M Operations and Maintenance Expense as a percentage of Average Net Distribution 

Plant calculated using RUS Bulletin 1724D-101A, Electric System Long-Range 

Planning Guide, based on RUS Fixed Charge Calculation Guide

0.00% TAX Property tax: annual Form 7, last year Part A, line 13(b)

Plant the taxes were paid on: annual Form 7, 2 years ago, Part C, line 5 + line 22

Tax Rate: (Property tax / Plant) x 100, or estimated future tax rate

3.24% DEP Most Owners use straight-line depreciation where the depreciation rate is the 

reciprocal of the asset’s life. Use annual rate for Co-op, for classes of plant 

Depreciation rate on RUS Form 7 Part E Lines 5(f) and line 6(f)

0.00% INS Insurance as a percentage of Net Distribution Plant.

Calculating the cost of insurance as a percentage of investment is difficult, and the 

result makes little difference, therefore, it can be ignored for most applications.

3.50% INF The annual inflation rate

30 m The loan amortization period in years

7.2&14.4 KV Line-to-ground voltage in kV

99.00% PF Peak month power factor

6.59% INT Cost of Capital (Calculated using RUS Fixed Charge Guide ) used for Present Worth 

Calculation

2.60% LGR The annual rate of growth projected for the peak demand (use latest PRS)

30 ULC Useful Life of Conductor

$0.00 $/kW Monthly demand charge in dollars per kW per month. If $/kW is zero, the following 

dependent inputs will also be zero:

0.00% kWI Demand charge inflation rate

0.00% CF Coincidence factor (this factor represents the coincidence between the noncoincident peak for the line and billing demand)

0.000 RMO The number of months the metered demand exceeds the minimum billing demand

0.000 RAT The annual demand ratchet expressed as a decimal

0.000 N The ratio of the average of the squares of the monthly kW demands for the months 

when the metered demand exceeds the minimum billing demand to the square of the 

peak month demand

$0.0689 $/kWh Energy charge in dollars per kWh per month

6.00% kWhI Energy charge inflation rate

43.70% LF Annual load factor
RUS Bulletin 1724D-101A

Exhibit E

Page 2

ABC ELECTRIC COOPERATIVE

CONDUCTOR LIFE CYCLE ANALYSIS

7.2 kV

Summary

Future Loading Based on a

Initial Loading 2.60% LGR for 30 Years

For loads below 1,378 kW use 1/0 ACSR 2,976 kW

For loads between 1,378 kW and 1,423 kW use 3/0 ACSR 2,976 kW

For loads between 1,423 kW and 1,779 kW use 336 ACSR 3,073 kW

For loads between 1,779 kW use 5,823 kW use 477 ACSR 3,842 kW

For loads above 5,823 kW use 795 ACSR 12,577 kW

Construction Costs

 Conductor Operating Capacity*

Conductor Cost Per Mile Ohms Per Mile† 100% 50%

3 Ø 1/0 ACSR $42,000 0.888 4,918 2,459 kW

3 Ø 3/0 ACSR $54,000 0.560 7,271 3,635 kW

3 Ø 336 ACSR $65,000 0.278 11,334 5,667 kW

3 Ø 477 ACSR $70,000 0.196 14,327 7,164 kW

3 Ø 795 ACSR $121,600 0.117 19,246 9,623 kW

† Resistance based on conductor operating temperature of 25°C (77°F) for Winter Loading.

* 100% Conductor Operating Capacity based on conductor temperature of 75°C (167°F), with a 25°C (77°F) 

ambient, with a and a 2 ft./sec wind, frequency = 60 Hz. Per Westinghouse T&D Reference Book, East Pittsburgh, 

Pa. (4th Edition: 11th Printing), 1950.
RUS Bulletin 1724D-101A

Exhibit E

Page 3

ABC ELECTRIC COOPERATIVE PLAN

CONDUCTOR LIFE CYCLE ANALYSIS

Total Life Cycle Cost — Three-Phase 7.2 kV

$100,000

$200,000

$300,000

$400,000

$500,000

$600,000

$700,000

$800,000

$900,000

$1,000,000

0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000

TLCC

($) / Mile

Initial Loading (kW)

1/0 ACSR 3/0 ACSR 336 ACSR

Patterson & 

5823

1378
RUS Bulletin 1724D-101A

Exhibit E

Page 4

ABC ELECTRIC COOPERATIVE

CONDUCTOR LIFE CYCLE ANALYSIS

14.4 kV

Summary

Future Loading based on a

Initial Loading 2.60% LGR for 30 Years

For loads below 2,756 kW use 1/0 ACSR 5,953 kW

For loads between 2,756 kW and 2,846 kW use 3/0 ACSR 5,953 kW

For loads between 2,846 kW and 3,559 kW use 336 ACSR 6,147 kW

For loads between 3,559 kW use 11,647 kW use 477 ACSR 7,687 kW

For loads above 11,647 kW use 795 ACSR 25,156 kW

Construction Costs

 Conductor Operating Capacity*

Conductor Cost Per Mile Ohms Per Mile 100% 50%

3 Ø 1/0 ACSR $42,000 0.888 9,837 4,918 kW

3 Ø 3/0 ACSR $54,000 0.560 14,541 7,271 kW

3 Ø 336 ACSR $65,000 0.278 22,667 11,334 kW

3 Ø 477 ACSR $70,000 0.196 28,655 14,327 kW

3 Ø 795 ACSR $121,600 0.117 38,491 19,246 kW

† Resistance based on conductor operating temperature of 25°C (77°F) for Winter Loading.

* 100% Conductor Operating Capacity based on conductor temperature of 75°C (167°F), with a 25°C (77°F) 

ambient, with a and a 2 ft./sec wind, frequency = 60 Hz. Per Westinghouse T&D Reference Book, East Pittsburgh, 

Pa. (4th Edition: 11th Printing), 1950.
RUS Bulletin 1724D-101A

Exhibit E

Page 5

ABC ELECTRIC COOPERATIVE

CONDUCTOR LIFE CYCLE ANALYSIS

Total Life Cycle Cost — Three-Phase 14.4 kV

$100,000

$200,000

$300,000

$400,000

$500,000

$600,000

$700,000

$800,000

$900,000

$1,000,000

1000 2000 3000 4000 5000 6000 7000 8000 9000 10000

Present Worth

Cost (Dollars)

Initial Loading (kW)

1/0 ACSR 3/0 ACSR 336 ACSR 477 ACSR 795 ACSR

Patterson & 

2756 3559
RUS Bulletin 1724D-101A

Exhibit F

Page 1

EXHIBIT F

SAMPLE SUBSTATION LOADING SHEET FOR SPECIFIC PLAN

ABC Electric Cooperative

City, State

2008 LONG-RANGE PLAN

SUBSTATION LOAD DATA

Plan D1 (Preferred Plan)

No. Substation Name

Voltage

kV

Xfmr Qty. Size 

MVA Existing Capacity

Proposed 

Capacity

%

Loaded

2006

Summer

2006 kW

SUBSTATION DEMANDS

2007 kW

2008 kW

2009 kW 2010 kW

LL2

2011 kW 2012 kW 2013 kW 2014 kW

LL3

2015 kW 2016 kW 2017 kW 2018 kW 2019 kW 2020 kW 2021 kW 2022 kW 2023 kW 2024 kW 2025 kW

LL4

2026 kW

1

Substation A

(- Substation O)

Total

115-25

115-25

1-10/12.5

1-10/12.5 12,500 12,500 65%

8,073

8,073

8,501

8,501

8,951

8,951

9,426

9,426

9,925

9,925

10,451

- 3,799

6,652

11,005

- 4,000

7,005

11,236

- 4,084

7,152

11,472

- 4,170

7,302

11,713

- 4,257

7,456

11,877

- 4,317

7,560

12,044

- 4,377

7,667

12,212

- 4,439

7,773

12,383

- 4,501

7,882

12,557

- 4,564

7,993

12,732

- 4,628

8,104

12,911

- 4,692

8,219

13,091

- 4,758

8,333

13,275

- 4,825

8,450

13,461

- 4,892

8,569

13,649

- 4,961

8,688

2

Substation B

Substation J

Total

115-12.5

115-12.5

1-10/12.5

1-10/12.5 12,500 12,500 36%

4,441

4,441

4,676

4,676

4,924

4,924

5,185

5,185

5,460

5,460

5,749

5,749

6,054

- 750

5,304

6,181

6,181

6,311

6,311

6,444

6,444

6,534

6,534

6,625

6,625

6,718

6,718

6,812

6,812

6,907

6,907

7,004

7,004

7,102

7,102

7,202

7,202

7,302

7,302

7,405

7,405

7,508

7,508

3

Substation C

(-switching w/ Substation F)

Substation F

Substation D

(- Substation O)

Total

115-25

115-25

1-10/12.5

1-10/12.5 12,500 12,500 76%

9,533

9,533

10,038

- 150

9,888

10,570

- 158

10,412

11,131

- 166

10,965

11,720

- 175

11,545

12,342

- 184

- 3,514

8,644

12,996

- 194

- 1,800

- 250

- 3,700

7,052

13,269

- 198

- 3,778

9,293

13,547

- 202

- 3,857

9,488

13,832

- 207

- 3,938

9,687

14,025

- 210

- 3,993

9,822

14,222

- 213

- 4,049

9,960

14,421

- 215

- 4,106

10,100

14,623

- 219

- 4,163

10,241

14,827

- 222

- 4,222

10,383

15,035

- 225

- 4,281

10,529

15,246

- 228

- 4,341

10,677

15,459

- 231

- 4,401

10,827

15,675

- 234

- 4,463

10,978

15,895

- 238

- 4,525

11,132

16,117

- 241

- 4,589

11,287

4

Substation D

(- Substation N)

(- Substation N)

(- Substation P)

Substation C

Total

115-25

115-25

1-12/16/20

1-12/16/20 20,000 20,000 60%

12,079

12,079

12,673

12,673

13,444

13,444

14,262

- 1,970

12,292

15,130

- 2,074

13,056

16,053

- 2,184

13,869

17,032

- 2,300

250

14,942

17,458

- 2,348

15,110

17,894

- 2,398

15,496

18,342

- 2,448

15,894

18,635

- 2,482

16,153

18,933

- 2,517

16,416

19,236

- 2,552

16,684

19,544

- 2,588

16,956

19,857

- 2,624

17,233

20,174

- 2,661

17,513

20,497

- 2,698

17,799

20,825

- 2,736

- 1,023

- 5,582

11,484

21,158

- 2,774

- 1,041

- 5,679

11,664

21,497

- 2,813

- 1,059

- 5,779

11,846

21,841

- 2,852

- 1,078

- 5,880

12,031

5

Substation E (old)

(-load to Substation E (new)) *1

Total

46-12.5

46-12.5

3-1.917

3-1.917 5,750 5,750 80%

4,604

4,604

4,848

4,848

5,105

- 5,105

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

5

Substation E (new)

+load from Substation E (old) *1

+load from Substation K*1

(-load to Substation M)*1

Total

46-12.5

46-12.5

1-12/16/20

1-12/16/20 0 20,000 0%

0

0

0

5,105

2,943

- 825

7,223

0

5,376

3,099

- 869

7,606

0

5,660

3,263

- 915

8,008

0

5,960

3,436

- 963

8,433

0

6,050

3,500

- 1,500

8,050

0

6,177

3,574

- 1,532

8,219

0

6,307

3,649

- 1,564

8,392

0

6,439

3,725

- 1,596

8,568

0

6,529

3,777

- 1,619

8,687

0

6,621

3,830

- 1,642

8,809

0

6,713

3,884

- 1,664

8,933

0

6,807

3,938

- 1,688

9,057

0

6,903

3,993

- 1,711

9,185

0

6,999

4,049

- 1,735

9,313

0

7,097

4,106

- 1,760

9,443

0

7,197

4,163

- 1,784

9,576

0

7,298

4,222

- 1,809

9,711

0

7,400

4,281

- 1,835

9,846

0

7,503

4,341

- 1,860

9,984

6

Substation F

+switching w/ Substation F

LP18 - existing prison*2

LP23 - new prison*2

Total

46-25

46-25

3-1.250

3-1.250 3,750 20,000 71%

2,662

0

0

2,662

2,803

150

1,000

0

3,953

2,952

158

1,500

0

4,610

3,108

166

2,000

0

5,274

3,273

175

2,000

1,500

6,948

3,446

184

2,000

1,500

7,130

3,629

250

2,100

1,575

7,554

3,705

255

2,205

1,654

7,819

3,783

261

2,315

1,736

8,095

3,862

266

2,431

1,823

8,382

3,916

270

2,553

1,914

8,653

3,971

274

2,680

2,010

8,935

4,027

277

2,814

2,111

9,229

4,083

281

2,955

2,216

9,535

4,140

285

3,103

2,327

9,855

4,198

289

3,258

2,443

10,188

4,257

293

3,421

2,566

10,537

4,317

297

3,592

2,694

10,900

4,377

302

3,771

2,828

11,278

4,438

306

3,960

2,970

11,674

4,501

310

4,158

3,118

12,087

7

Substation G

uprate in 2011

Total

115-12.5

115-12.5

1-10

1-10 10,000 20,000 74%

7,407

7,407

7,898

7,898

8,422

8,422

8,980

8,980

9,575

9,575

10,210

10,210

10,200

10,200

10,468

10,468

10,744

10,744

11,026

11,026

11,219

11,219

11,415

11,415

11,615

11,615

11,818

11,818

12,025

12,025

12,236

12,236

12,450

12,450

12,668

12,668

12,889

12,889

13,115

13,115

13,344

13,344

8

Substation H

(- Substation Q)

Total

115-25

115-25

1-10/12.5

1-10/12.5 12,500 20,000 88%

10,946

10,946

11,672

11,672

12,446

12,446

13,271

13,271

14,151

14,151

15,089

15,089

15,100

15,100

15,497

15,497

15,905

15,905

16,323

16,323

16,609

16,609

16,899

16,899

17,195

17,195

17,496

17,496

17,802

- 3,563

14,239

18,114

- 3,625

14,489

18,431

- 3,689

14,742

18,753

- 3,753

15,000

19,081

- 3,819

15,262

19,415

- 3,886

15,529

19,755

- 3,954

15,801

9

Substation I

(- Substation N)

(- Substation P)

Total

115-25

115-25

1-10/12.5

1-10/12.5 12,500 12,500 76%

9,451

9,451

10,078

10,078

10,746

10,746

11,458

- 5,650

5,808

12,218

- 6,025

6,193

13,028

- 6,424

6,604

13,892

- 6,850

7,042

14,257

- 7,030

7,227

14,632

- 7,215

7,417

15,017

- 7,405

7,612

15,280

- 7,534

7,746

15,547

- 7,666

7,881

15,819

- 7,800

8,019

16,096

- 7,937

8,159

16,378

- 8,076

8,302

16,664

- 8,217

8,447

16,956

- 8,361

8,595

17,253

- 8,507

- 4,770

3,976

17,554

- 8,656

- 4,854

4,044

17,862

- 8,808

- 4,939

4,115

18,174

- 8,962

- 5,025

4,187

10

Substation J

(- Substation O)

Total

115-25

115-25

1-12/16/20

1-12/16/20 20,000 20,000 62%

12,349

12,349

13,051

13,051

13,833

13,833

14,661

14,661

15,541

15,541

16,473

- 4,274

12,199

17,462

- 4,500

12,962

17,899

- 4,595

13,304

18,346

- 4,691

13,655

18,805

- 4,789

14,016

19,106

- 4,857

14,249

19,411

- 4,925

14,486

19,722

- 4,993

14,729

20,037

- 5,063

14,974

20,358

- 5,134

15,224

20,684

- 5,206

15,478

21,015

- 5,279

15,736

21,351

- 5,353

15,998

21,692

- 5,428

16,264

22,040

- 5,504

16,536

22,392

- 5,581

16,811

11

Substation K

(-Substation K Abandoned)

Total

46-12.5

46-12.5

3-2.5

3-2.5 7,500 7,500 48%

3,606

3,606

3,797

3,797

0

- 3,797

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

12

Substation L

+load from Substation K*1

(- Substation L 25kV 25kV)

Total

115-12.5

115-12.5

1-12/16/20

1-12/16/20 12,500 20,000 93%

11,667

11,667

12,441

12,441

13,265

0

13,265

14,145

0

14,145

15,083

0

-12,543

2,540

16,083

0

-13,374

2,709

16,800

0

-14,261

2,539

17,242

0

-14,636

2,606

17,695

0

-15,021

2,674

18,161

0

-15,416

2,745

18,478

0

-15,686

2,792

18,802

0

-15,960

2,842

19,131

0

-16,240

2,891

19,466

0

-16,524

2,942

19,806

0

-16,813

2,993

20,153

0

-17,107

3,046

20,506

0

-17,407

3,099

20,864

0

-17,711

3,153

21,230

0

-18,021

3,209

21,601

0

-18,337

3,264

21,979

0

-18,657

3,322

12

Substation L 25kV 25kV

(-Substation Q)

Total

115-25

115-25

1-12/16/20

1-12/16/20 0 20,000 0%

0

0 0 0 0

12,543

12,543

13,374

13,374

14,261

14,261

14,636

14,636

15,021

15,021

15,416

15,416

15,686

15,686

15,960

15,960

16,240

16,240

16,524

16,524

16,813

- 1,247

15,566

17,107

- 1,269

15,838

17,407

- 1,291

16,116

17,711

- 1,314

16,397

18,021

- 1,337

16,684

18,337

- 1,360

16,977

18,657

- 1,384

17,273

13

Substation M

+load from Substation E (old)*1

Total

46-12.5

46-12.5

3-.833

3-.833 2,500 20,000 94%

2,354

2,354

2,479

2,479

2,610

825

3,435

2,748

869

3,617

2,894

915

3,809

3,048

963

4,011

3,209

850

4,059

3,276

868

4,144

3,345

886

4,231

3,415

905

4,320

3,463

917

4,380

3,512

930

4,442

3,561

943

4,504

3,611

956

4,567

3,661

970

4,631

3,713

983

4,696

3,765

997

4,762

3,817

1,011

4,828

3,871

1,025

4,896

3,925

1,040

4,965

3,980

1,054

5,034

14 Substation N

Total

115-25

115-25

1-12/16/20

1-12/16/20 0 20,000 0%

0

0

0

0

16,100

16,100

16,100

16,100

16,100

16,100

16,100

16,100

16,100

16,100

16,100

16,100

16,100

16,100

16,100

16,100

16,100

16,100

16,100

16,100

16,100

16,100

16,100

16,100

16,100

16,100

16,100

16,100

16,100

16,100

16,100

16,100

16,100

16,100

16,100

16,100

16,100

16,100

14

Substation N - 2nd Transformer

+load from Substation I

+load from Substation D

+load from Substation D

(-load to Substation P)

Total

115-25

115-25

1-12/16/20

1-12/16/20 0 20,000 0%

0

0

0

0

0

0

0

5,050

1,970

7,020

0

5,384

2,074

7,458

0

5,741

2,184

7,925

0

5,800

2,000

7,800

0

5,953

2,042

7,995

0

6,109

2,085

8,194

0

6,270

2,129

8,398

0

6,379

2,158

8,537

0

6,491

2,189

8,680

0

6,605

2,219

8,824

0

6,720

2,250

8,970

0

6,838

2,282

9,120

0

6,958

2,314

9,272

0

7,079

2,346

9,425

0

7,203

2,379

1,023

- 2,106

8,499

0

7,329

2,412

1,041

- 2,143

8,639

0

7,458

2,446

1,059

- 2,181

8,782

0

7,588

2,480

1,078

- 2,219

8,927

15

Substation O

+load from Substation A

+load from Substation C

+load from Substation J

Total

115-25

115-25

1-12/16/20

1-12/16/20 0 20,000 0%

0

0

0

0

0

0

0

0

0

0

0

3,086

3,514

3,751

10,351

0

3,200

3,200

3,600

10,000

0

3,267

3,267

3,676

10,210

0

3,336

3,336

3,753

10,425

0

3,406

3,406

3,832

10,644

0

3,454

3,454

3,885

10,793

0

3,502

3,502

3,940

10,944

0

3,551

3,551

3,995

11,097

0

3,601

3,601

4,051

11,253

0

3,651

3,651

4,107

11,409

0

3,702

3,702

4,165

11,569

0

3,754

3,754

4,223

11,731

0

3,807

3,807

4,282

11,896

0

3,860

3,860

4,342

12,062

0

3,914

3,914

4,403

12,231

0

3,969

3,969

4,465

12,403

16

Substation P

+load from Substation D

+load from Substation I

+load from Substation N

Total

115-25

115-25

1-12/16/20

1-12/16/20 0 20,000 0%

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

5,582

4,770

2,106

12,458

0

5,679

4,854

2,143

12,676

0

5,779

4,939

2,181

12,899

0

5,880

5,025

2,219

13,124

17

Substation Q

+load from Substation L 25kV 25kV

+load from Substation H

Total

115-25

115-25

1-12/16/20

1-12/16/20 0 20,000 0%

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

0

1,247

3,563

4,810

0

1,269

3,625

4,894

0

1,291

3,689

4,980

0

1,314

3,753

5,067

0

1,337

3,819

5,156

0

1,360

3,886

5,246

0

1,384

3,954

5,338

System Total 144,500 343,250 69% 99,172 105,955 127,811 134,350 142,852 149,049 149,970 155,961 159,450 163,031 165,520 168,061 170,651 173,286 175,975 178,716 181,513 184,362 187,264 190,231 193,249
RUS Bulletin 1724D-101A

Exhibit G

Page 1

EXHIBIT G

SAMPLE PLAN ECONOMIC ANALYSIS SPREADSHEET

Client Name: ABC ELECTRIC COOPERATIVE

Plan Number: PLANS A, B, C, D, D1, D1A

Assumptions: See Detail Plan Analysis

Number of Years for This Comparison: 18

FIRST YEAR OF STUDY 2008

Power Power

Distributor Supplier

1. Energy Cost/kWh ($) $0.0689 $0.04300

2. Present Worth Interest Rate (%) 6.00% 6.00%

3. Annual Fixed Charge (%) 9.83% 10.50%

4. T&D O&M Costs (%) 6.23% 0.00%

5. Substation O&M Costs (%) 0.00% 0.00%

6. Inflation Rate (%) 3.50% 3.50%

7. Energy Inflation Rate (%) 6.00% 2.88%

8. Additional Delivery Point Charge ($) —

9. Percent of Dist. Line Insulated for 25kV 0%

Note: Annual Fixed Charge only includes interest, depreciation, taxes, and insurance rates.

O&M costs inflate with Inflation Rate.

Energy costs inflate with Energy Inflation Rate.
RUS Bulletin 1724D-101A

Exhibit G

Page 2

ABC ELECTRIC COOPERATIVE

City, State

2008 LONG-RANGE PLAN

ECONOMIC COMPARISONS

(2008 DOLLARS)

PLAN SUMMARY

Plan A No New Delivery Points Added and Distribution Lines to Remain at Current Voltage Levels

Plan B No New Delivery Points Added and All Distribution Voltage Converted to 25 kV

Plan C New Delivery Points Added and Distribution Lines Remain at Current Voltage Levels

Plan D New Delivery Points Added and Distribution Voltage Converted to 25 kV

Plan D1 Like D, but Substation B Added Instead of Substation A

Plan D1A Like D1, but Substation C Served from G&T 115-kV Transmission Line

PRESENT WORTH ECONOMIC ANALYSIS

Distributor Distributor Preferred

G&T ABC EC Losses Losses Plan

Power Wheeling Power at Distributor at Supplier One Cost

Supplier Costs Distributor Cost Cost Ownership Difference

Plan A $16,548,914 $11,448,005 $18,372,961 $10,862,380 $5,167,561 $51,537,441 $1,494,069

Plan B $17,455,913 $11,448,005 $23,150,650 $9,775,706 $4,684,871 $56,739,439 $6,696,067

Plan C $17,777,867 $12,095,507 $16,677,014 $10,486,111 $5,000,427 $51,550,815 $1,507,443

Plan D*1 $18,959,550 $11,646,030 $14,680,545 $9,858,514 $4,721,654 $50,007,779 ($35,593)

Plan D1 $20,207,558 $9,922,383 $15,267,278 $9,688,539 $4,646,153 $50,043,372 $0

Plan D1A $22,301,687 $8,374,892 $15,267,278 $9,688,539 $4,646,153 $50,590,010 $546,638

CONSTRUCTION COSTS AND LOSSES SUMMARY

ABC EC ABC EC Preferred

G&T Power Power Total Cost of Plan

Power Wheeling Distributor Total Distributor Construction Cost

Supplier Costs Costs Costs Costs Losses and Losses Difference

Plan A $14,648,138 $19,381,592 $18,217,063 $52,246,793 $10,862,380 $63,109,173 $180,212

Plan B $16,128,849 $19,381,592 $22,958,945 $58,469,386 $9,775,706 $68,245,092 $5,316,131

Plan C $15,268,138 $20,863,794 $16,501,473 $52,633,405 $10,486,111 $63,119,516 $190,555

Plan D $17,248,849 $19,957,572 $16,263,577 $53,469,998 $9,858,514 $63,328,512 $399,551

Plan D1 $19,811,349 $16,545,686 $16,883,387 $53,240,422 $9,688,539 $62,928,961 $0

Plan D1A $21,811,349 $13,835,086 $16,883,387 $52,529,822 $9,688,539 $62,218,361 ($710,600)

Note: Highlight indicates the Preferred Plan. The Preferred Alternate Plan is Plan D1A.

 *1 Due to operational reasons, this plan is not considered a viable option.
RUS Bulletin 1724D-101A

Exhibit G

Page 3

ABC CONSULTANT—ECONOMIC COMPARISON PROGRAM

Client Name: ABC ELECTRIC COOPERATIVE

Plan Number: PLAN D1

Number of years for this comparison: 18

MAXIMUM YEARS = 30

Power Energy

Distributor Supplier

1. Energy Cost/kWh ($) $0.0689 $0.0430

2. Present Worth Interest Rate (%) 6.00% 6.00%

3. Annual Fixed Charge (%) 9.83% 10.50%

4. T&D O&M Costs (%) 6.23% 0.00%

5. Substation O&M Costs (%) 0.00% 0.00%

6. Inflation Rate (%) 3.50% 3.50%

7. Energy Inflation Rate (%) 6.00% 2.88%

8. Annual Delivery Point Charge ($) —

Note: Annual Fixed Charge only includes interest, depreciation, taxes, and insurance rates.

O&M costs inflate with Inflation Rate.

Energy costs inflate with Energy Inflation Rate.

Cost Summary—Present Worth Dollars

Power Power One

Supplier Distributor Ownership

Transmission & Substation $20,207,558 — $20,207,558

Substation & Distribution — $15,267,278 15,267,278

 Subtotal 20,207,558 15,267,278 35,474,836

Delivery Point (Rev./Costs) 0 0 0

Wheeling Charges 9,922,383 — 9,922,383

Transmission Losses 0 — 0

Distribution Losses (Rev./Costs) (9,688,539) 9,688,539 0

Distribution Losses at Supplier Cost 4,646,153 — 4,646,153

 Totals $25,087,555 $24,955,817 $50,043,372
RUS Bulletin 1724D-101A

Exhibit G

Page 4

ABC CONSULTANT—ECONOMIC COMPARISON PROGRAM

Client Name: ABC ELECTRIC COOPERATIVE

Plan Number: PLAN D1

Distributor Costs Present Worth Present

Present of Inflated Number Worth of

Distribution Sub&Trans Total Inflated Inflated Inflated Annual Annual Total Worth of Annual Annual of Delivery

Construction Construction Construction Distribution Substation Construction O&M Fixed Annual Distributor Distribution Distribution Delivery Point

Year Costs Costs Costs Costs Costs Costs Costs Costs Costs Annual Costs Losses Losses Points Charges

2008 757,388 100,000 857,388 757,388 100,000 857,388 47,185 84,281 131,467 131,467 $469,322 469,322 2 0

2009 757,388 50,000 807,388 783,897 51,750 835,647 96,022 166,425 262,447 247,592 $473,833 473,833 2 0

2010 757,388 50,000 807,388 811,333 53,561 864,894 146,568 251,444 398,012 354,230 $478,344 478,344 2 0

2011 757,388 75,000 832,388 839,730 83,154 922,883 198,883 342,164 541,047 454,274 $482,856 482,856 2 0

2012 757,388 0 757,388 869,120 0 869,120 253,029 427,598 680,628 539,121 $487,367 487,367 2 0

2013 757,388 0 757,388 899,539 0 899,539 309,071 516,023 825,094 616,558 $491,878 491,878 2 0

2014 757,388 0 757,388 931,023 0 931,023 367,073 607,543 974,616 687,066 $496,389 496,389 2 0

2015 757,388 0 757,388 963,609 0 963,609 427,106 702,265 1,129,372 751,097 $500,901 500,901 2 0

2016 757,388 0 757,388 997,335 0 997,335 489,240 800,303 1,289,544 809,076 $505,412 505,412 2 0

2017 757,388 0 757,388 1,032,242 0 1,032,242 553,549 901,773 1,455,322 861,403 $509,923 509,923 2 0

2018 757,388 0 757,388 1,068,371 0 1,068,371 620,108 1,006,794 1,626,902 908,454 $514,434 514,434 2 0

2019 757,388 0 757,388 1,105,764 0 1,105,764 688,998 1,115,490 1,804,488 950,582 $518,946 518,946 2 0

2020 757,388 0 757,388 1,144,465 0 1,144,465 760,298 1,227,991 1,988,289 988,119 $523,457 523,457 2 0

2021 757,388 50,000 807,388 1,184,522 78,198 1,262,719 834,093 1,352,117 2,186,210 1,024,981 $527,968 527,968 2 0

2022 757,388 0 757,388 1,225,980 0 1,225,980 910,472 1,472,630 2,383,102 1,054,048 $532,479 532,479 2 0

2023 757,388 50,000 807,388 1,268,889 83,767 1,352,657 989,524 1,605,596 2,595,120 1,082,853 $536,991 536,991 2 0

2024 1,463,393 0 1,463,393 2,537,503 0 2,537,503 1,147,610 1,855,033 3,002,643 1,181,979 $541,502 541,502 2 0

2025 1,463,393 0 1,463,393 2,626,316 0 2,626,316 1,311,230 2,113,200 3,424,430 1,271,711 $546,013 546,013 2 0

2026 1,463,393 0 1,463,393 2,718,237 0 2,718,237 1,480,576 2,380,403 3,860,978 1,352,670 $550,524 550,524 2 0

Totals 16,508,387 375,000 16,883,387 23,765,262 450,430 24,215,692 11,630,636 18,929,075 30,559,711 15,267,278 9,688,539 9,688,539 0

Supplier Costs Present

Present Worth Inflated Worth

Present of Inflated Distribution Inflated

Transmission Substation Total Inflated Inflated Inflated Annual Annual Total Worth of Annual Annual Losses at Distribution

Construction Construction ConstructionTransmission Substation Construction O&M Fixed Annual Supplier Transmission Transmission Supplier Losses at

Year Costs Costs Costs Costs Costs Costs Costs Costs Costs Annual Cost Losses Losses Cost Supplier Cost

2008 2,973,138 4,800,000 7,773,138 2,973,138 4,800,000 7,773,138 0 816,179 816,179 816,179 0 0 292,900 292,900

2009 0 3,100,000 3,100,000 0 3,208,500 3,208,500 0 1,153,072 1,153,072 1,087,804 0 0 304,233 287,012

2010 0 1,475,000 1,475,000 0 1,580,057 1,580,057 0 1,318,978 1,318,978 1,173,886 0 0 315,974 281,216

2011 2,057,500 1,475,000 3,532,500 2,281,187 1,635,359 3,916,546 0 1,730,215 1,730,215 1,452,722 0 0 328,140 275,513

2012 0 0 0 0 0 0 0 1,730,215 1,730,215 1,370,493 0 0 340,745 269,902

2013 0 0 0 0 0 0 0 1,730,215 1,730,215 1,292,918 0 0 353,803 264,382

2014 0 480,711 480,711 0 590,917 590,917 0 1,792,262 1,792,262 1,263,474 0 0 367,331 258,954

2015 0 0 0 0 0 0 0 1,792,262 1,792,262 1,191,956 0 0 381,345 253,616

2016 0 0 0 0 0 0 0 1,792,262 1,792,262 1,124,487 0 0 395,861 248,368

2017 0 0 0 0 0 0 0 1,792,262 1,792,262 1,060,837 0 0 410,897 243,209

2018 0 0 0 0 0 0 0 1,792,262 1,792,262 1,000,789 0 0 426,470 238,139

2019 0 0 0 0 0 0 0 1,792,262 1,792,262 944,141 0 0 442,600 233,156

2020 0 0 0 0 0 0 0 1,792,262 1,792,262 890,699 0 0 459,305 228,261

2021 250,000 1,475,000 1,725,000 390,989 2,306,835 2,697,824 0 2,075,533 2,075,533 973,091 0 0 476,606 223,451

2022 0 0 0 0 0 0 0 2,075,533 2,075,533 918,010 0 0 494,522 218,727

2023 250,000 1,475,000 1,725,000 418,837 2,471,140 2,889,977 0 2,378,981 2,378,981 992,665 0 0 513,074 214,088

2024 0 0 0 0 0 0 0 2,378,981 2,378,981 936,477 0 0 532,285 209,532

2025 0 0 0 0 0 0 0 2,378,981 2,378,981 883,469 0 0 552,177 205,059

2026 0 0 0 0 0 0 0 2,378,981 2,378,981 833,461 0 0 572,774 200,668

Totals 5,530,638 14,280,711 19,811,349 6,064,151 16,592,807 22,656,958 0 34,691,695 34,691,695 20,207,558 0 0 7,961,042 4,646,153
RUS Bulletin 1724D-101A

Exhibit G

Page 5

ABC CONSULTANT—ECONOMIC COMPARISON PROGRAM

Client Name: ABC ELECTRIC COOPERATIVE

Plan Number: PLAN D1

One-Ownership Costs

Present

Worth of

Total Annual Total Annual

Year Costs Costs

2008 947,646 947,646

2009 1,415,519 1,335,396

2010 1,716,990 1,528,115

2011 2,271,262 1,906,996

2012 2,410,843 1,909,614

2013 2,555,309 1,909,476

2014 2,766,878 1,950,540

2015 2,921,633 1,943,053

2016 3,081,805 1,933,563

2017 3,247,583 1,922,240

2018 3,419,164 1,909,243

2019 3,596,749 1,894,723

2020 3,780,550 1,878,818

2021 4,261,743 1,998,071

2022 4,458,635 1,972,059

2023 4,974,101 2,075,518

2024 5,381,624 2,118,456

2025 5,803,410 2,155,180

2026 6,239,959 2,186,131

Total 65,251,405 35,474,836
RUS Bulletin 1724D-101A

Exhibit H

Page 1

EXHIBIT H

SAMPLE SENSITIVITY ANALYSES

ABC ELECTRIC COOPERATIVE

City, State

2008 LONG-RANGE PLAN

One-Ownership Present Worth Sensitivity Analysis*

% Inflation Rate Plan D Plan D1 Plan D1A

1.0% $47,431,239 $47,149,289 $47,547,814

1.5% $47,907,257 $47,683,278 $48,110,847

2.0% $48,401,963 $48,238,569 $48,695,471

2.5% $48,916,286 $48,816,245 $49,302,769

3.0% $49,451,214 $49,417,445 $49,933,880

3.5% $50,007,779 $50,043,372 $50,590,010

4.0% $50,587,073 $50,695,289 $51,272,423

4.5% $51,190,240 $51,374,529 $51,982,454

5.0% $51,818,489 $52,082,495 $52,721,508

% Load Growth Plan D Plan D1 Plan D1A

2.71% $56,200,499 $56,038,290 $56,526,398

3.40% $50,007,779 $50,043,372 $50,590,010

4.56% $41,131,306 $41,422,929 $42,091,843

Energy

Inflation Rate Plan D Plan D1 Plan D1A

1.0% $49,349,487 $49,398,720 $49,945,358

2.0% $49,683,345 $49,725,701 $50,272,339

3.0% $50,054,417 $50,089,032 $50,635,670

4.0% $50,467,206 $50,493,103 $51,039,741

5.0% $50,926,763 $50,942,841 $51,489,479

6.0% $51,438,753 $51,443,768 $51,990,406

7.0% $52,009,526 $52,002,075 $52,548,713

Present

Worth Rate Plan D Plan D1 Plan D1A

4.0% $59,834,287 $59,930,497 $60,592,357

5.0% $54,605,925 $54,668,875 $55,269,305

6.0% $50,007,779 $50,043,372 $50,590,010

7.0% $45,952,166 $45,965,294 $46,464,672

8.0% $42,364,821 $42,359,541 $42,817,259

9.0% $39,182,695 $39,162,372 $39,583,243

Wheeling Cost Plan D Plan D1 Plan D1A

$2.00 $49,449,552 $49,616,093 $50,229,369

$2.50 $52,221,503 $51,989,868 $52,232,932

$3.00 $54,993,453 $54,363,644 $54,236,495

$3.50 $57,765,404 $56,737,420 $56,240,057

$4.00 $60,537,355 $59,111,196 $58,243,620

$4.50 $63,309,305 $61,484,972 $60,247,183

$5.00 $66,081,256 $63,858,748 $62,250,746

$5.50 $68,853,207 $66,232,524 $64,254,309

$6.00 $71,625,158 $68,606,300 $66,257,871

* For the three closest plans with different design approaches.
RUS Bulletin 1724D-101A

Exhibit H

Page 2

$47,000,000

$48,000,000

$49,000,000

$50,000,000

$51,000,000

$52,000,000

$53,000,000

1.0% 1.5% 2.0% 2.5% 3.0% 3.5% 4.0% 4.5% 5.0%

One Ownership PW Amount

Inflation Rate

ABC ELECTRIC COOPERATIVE 

City, State

Sensitivity Analysis

Plan

D

Plan

D1

$40,000,000

$42,000,000

$44,000,000

$46,000,000

$48,000,000

$50,000,000

$52,000,000

$54,000,000

$56,000,000

$58,000,000

2.71% 3.40% 4.56%

One Ownership PW Amount

Load Growth Rates

ABC ELECTRIC COOPERATIVE

City, State

Sensitivity Analysis

Plan

D

Plan

D1

Plan

D1A
RUS Bulletin 1724D-101A

Exhibit H

Page 3

$49,000,000

$49,500,000

$50,000,000

$50,500,000

$51,000,000

$51,500,000

$52,000,000

$52,500,000

$53,000,000

1 2 3 4 5 6 7

One Ownership PW Amount

Energy Inflation Rate

ABC ELECTRIC COOPERATIVE 

City, State

Sensitivity Analysis

Plan

D

Plan

D1

Plan

D1A

$35,000,000

$40,000,000

$45,000,000

$50,000,000

$55,000,000

$60,000,000

1 2 3 4 5 6

One Ownership PW Amount

Present Worth Rate

ABC ELECTRIC COOPERATIVE 

City, State

Sensitivity Analysis

Plan

D

Plan

D1

Plan

D1A
RUS Bulletin 1724D-101A

Exhibit H

Page 4

$48,000,000

$53,000,000

$58,000,000

$63,000,000

$68,000,000

$73,000,000

$2.00 $2.50 $3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00

One Ownership PW Amount

Wheeling Cost $/kW

ABC ELECTRIC COOPERATIVE 

City, State

Sensitivity Analysis

Plan

D

Plan

D1

Plan

D1A
RUS Bulletin 1724D-101A

Exhibit I

Page 1

EXHIBIT I

SUGGESTED TABLE OF CONTENTS FOR LONG-RANGE ENGINEERING PLAN

ABC ELECTRIC COOPERATIVE

2008 LONG-RANGE PLAN

TABLE OF CONTENTS

LETTER OF TRANSMITTAL AND ENGINEERING CERTIFICATION ............................i

CHECKLIST OF SYSTEM PLANNING REPORT (RUS Form 260) .....................................ii

SUMMARY OF SYSTEM PLANNING REPORT (RUS Form 261) ......................................iv

GENERAL COOPERATIVE LOCATION MAP ......................................................................v

I. INTRODUCTION ...............................................................................................................1

II. PURPOSE OF REPORT .....................................................................................................3

III. SUMMARY OF REPORT AND RECOMMENDATIONS ............................................4

IV. ANALYSIS OF EXISTING SYSTEM AND BASIC DATA ...........................................5

A. Introduction ......................................................................................................5

B. Purpose of Analysis .........................................................................................5

C. Summary, Conclusion, and Recommendations ................................5

D. System Growth Patterns .............................................................................5

E. Capacity of Existing System ......................................................................5

F. Environmentally Sensitive Areas ..........................................................6

G. Adequacy of Basic Data ...............................................................................6

V. PLANNING CRITERIA .....................................................................................................7

A. Long-Range Demand Level ..........................................................................7

B. Area Load Density and Growth Potential ........................................7

C. Special Loads ......................................................................................................7

D. Service Reliability ..........................................................................................8

E. Engineering and Economic Criteria (Eec) ...........................................8

F. Financial Criteria ...........................................................................................8

G. Other Criteria ....................................................................................................9

H. Assumptions .........................................................................................................9

I. Facilities and EQUIPMENT ..............................................................................9

VI. LONG-RANGE PLAN .....................................................................................................10

A. Exploratory Plans ........................................................................................10

B. Plan Selection ..................................................................................................11

C. The Recommended Plan ...............................................................................12

D. Alternate Plans Reviewed ........................................................................13

1. Plan D1a—Alternate Preferred Plan ...........................................13

VII. CONCLUSION ..................................................................................................................14

EXHIBITS

EXHIBIT 1 System Statistical Data

EXHIBIT 2 Substation Load Data
RUS Bulletin 1724D-101A

Exhibit I

Page 2

EXHIBIT 3 Engineering and Economic Criteria

EXHIBIT 4 Consumer Outage Summary

EXHIBIT 5 RUS Fixed Charge Summary

EXHIBIT 6 Economic Parameters and Cost Estimates

EXHIBIT 7 Summary of Total Plant Investment

EXHIBIT 8 Summary of Estimated Capital Additions to Distribution Plant

EXHIBIT 9 Summary of Estimated System Distribution Improvement Costs

EXHIBIT 10 Cost Estimates, New Services

EXHIBIT 11 Cost Estimates, Distribution Line Construction

EXHIBIT 12 Cost Estimates, Transmission Facilities

EXHIBIT 13 Cost Estimates, Substations

EXHIBIT 14 Cost Estimates, Uprating Existing Services

EXHIBIT 15 Cost Estimates, Miscellaneous Distribution Equipment

EXHIBIT 16 Cost Estimates, Ordinary Replacements

EXHIBIT 17 Estimated Distribution Plant Investment Charts

EXHIBIT 18 Economic Comparisons of Plans Reviewed

EXHIBIT 19 Sensitivity Analysis

EXHIBIT 20 Conductor Life Cycle Analysis

EXHIBIT 21 Transmission System (Existing System with LL4 Improvements)

MAPS*

Map 1 Existing Summer 2006 Base System, Load Level 1

Map 2 Proposed Summer 2026 System, Load Level 4

*Maps for Preferred Plan D1 only. Alternate plans are available upon request. See supporting data for primary 

analyses of system conditions.

SUPPORTING DATA

Other appropriate information and data that substantiate the conclusions made in this report have

been bound under separate cover and are available from Patterson & Dewar Engineers and ABC

Electric Cooperative upon request.
RUS Bulletin 1724D-101A

Exhibit J

Page 1

EXHIBIT J

SUGGESTED TABLE OF CONTENTS OF SUPPORTING DATA

ABC ELECTRIC COOPERATIVE

2008 LONG-RANGE PLAN

SUPPORTING DATA

TABLE OF CONTENTS

TAB A Summary of Plans

TAB B Large Power Loads (Summer 2006)

TAB C Economic Parameters and Cost Estimates

TAB D Growth Projections

TAB E Generation and Transmission Correspondence and Cost Estimates

TAB F RUS Fixed Charge Summary

TAB G Summary of Economic Comparisons with Plan Calculation Tabs

TAB H Sensitivity Analysis (Details)

Inflation

Load Growth

Energy Inflation

Present Worth Rate

PLAN D1 (Preferred Plan) **

TAB I Add 3 new delivery points (DPs). Convert the rest of Substations C, E, and F to 25kV.

Transmission System

Substation Loading

Losses Allocations

Cost Allocations

TAB J Primary Analysis, Load Level 1—Existing System Summer 2006

TAB K Primary Analysis, Load Level 2—Proposed System Summer 2012

(2008 Construction Work Plan)

TAB L Primary Analysis, Load Level 3—Proposed System Summer 2016

** See main long-range study report for further details of the Preferred Plan results.
RUS Bulletin 1724D-101A

Exhibit K

Page 1

EXHIBIT K

CHECKLIST OF LONG-RANGE PLANNING REPORT (RUS FORM 260)

U. S. DEPARTMENT OF AGRICULTURE

RURAL UTILITIES SERVICE

CHECK OF SYSTEM PLANNING REPORT

Reference Bulletin 1724D-101A

BORROWER DESIGNATION

xx-xxx-xxxxxxx

DATE REPORT COMPLETED NAME OF PLANNING ENGINEER

 

CHECK PART I - THE SYSTEM PLANNING REPORT

(If “No” column is checked, explain under “Remarks”)

YES NO

 1. Does the report present an analysis of the existing system and basic data?

 2. Does the report present a transition from the existing system to the long-range system?

 3. Does the report contain a summary of the exploratory plans which the engineer considered?

 4. Did the borrower have a service reliability standard for the engineer to use as a means of 

evaluating continuity and reliability of service to consumers?

 5. Was each exploratory plan developed in sufficient detail to clearly establish the basis for 

selection of the recommended plan?

 6. Have all reasonable exploratory plans been considered?

 7. Have the transitional steps been formed by grouping together various system improvements 

requiring approximately the same load level?

 8. Are graphs presented relating estimated total plant investment to load levels?

 9. Is a table presented listing the fixed cost elements and the associated percentage of plant 

investment used for the economic comparisons?

10. Are economic comparisons of exploratory plans presented on an annual cost basis?

11. Are summaries of cost data tabulated and identified as called for in Bulletin 1724D-101A 

(6.5.4)?

12. Does the report contain a circuit diagram of the complete system for each major step in the 

transition and for the long-range system as called for in Bulletin 1724D-101A(6.5.6)?

13. Are the system’s transmission lines, if any, and those of the power supplier or other utilities 

in or near the system’s service area shown on the circuit diagrams or other diagrams?

14. Is the report, including the analysis of the existing system, concise and well-organized so that 

management can easily work with the report without further engineering interpretation?

15. Has a copy of a resolution signifying the board of directors’ action concerning acceptance of 

the report been received?

DATE SIGNATURE

RUS FORM 260 — CAB (7/96) 5-68
RUS Bulletin 1724D-101A

Exhibit K

Page 2

CHECK PART II—DEVELOPMENT OF THE LONG-RANGE PLAN

YES NO

 1. Does the analysis of the existing system give a good understanding of the system’s 

performance?

 2. Is the load level for the long-range system within the range of three to six times the average 

kwh/consumer/month for the highest peak month experienced to date?

 3. Does each exploratory plan presented, including the long-range plan, make use of existing 

facilities as long as it is economical to do so?

 4. Does each exploratory plan presented, including the long-range plan, provide a system which 

is designed to meet the required voltage standards?

 5. Does the transition from the existing system to the long-range system demonstrate a practical 

and economical development of the system?

 6. Are proposed voltage regulator installations in the long-range plan in accordance with the 

recommendations in RUS Bulletin 1724D-101A?

 7. Are the cost estimates used by the engineer reasonable?

 8. Are the design criteria established by management reasonable so that they do not rule out 

logical exploratory plans?

 9. In addition to the economic comparisons, are sufficient comparisons and considerations made 

to show the superiority of the selected long-range plan over the other exploratory plans?

10. If indeterminate factors or uncertain conditions exist, is an alternate transition from the 

existing system to the long-range system proposed?

11. Is the proposed long-range plan based on power sources that the engineer and the system’s 

management are reasonably sure will be available?

REMARKS

DATE COMPLETED BY — SIGNATURE

RUS FORM 260 — CAB (7/96) 5-68
RUS Bulletin 1724D-101A

Exhibit L

Page 1

EXHIBIT L

SUMMARY OF LONG-RANGE PLANNING REPORT (RUS FORM 261)

SUMMARY OF SYSTEM

PLANNING REPORT

SYSTEM DESIGNATION DATE PLANNING REPORT COMPLETED

PLANNING ENGINEER

PART I—GENERAL DATA

ITEMS

1.

2. LINE MILES 3. NO. OF CONSUMERS

TOTAL

SYSTEM

LOADS 

(kW)

4.

TOTAL

SPECIAL

LOADS 

(kW)

5.

TOTAL

YEARLY 

SALES

(kWh)

6.

7. PAST PEAK LOAD

DESIGN

LOAD

kWh/CONS.

/MO.

PEAK MO.

8.

TRANS.

a.

DISTR.

b.

ALL 

TYPES

(Including

special 

loads)

c.

SPECIAL

LOADS

d.

kWh/CONS.

/MO.

a.

DATE

b.

PRESENT

SYSTEM AS

OF________

LONGRANGE

PLAN

PART II—LINE MILES

ITEMS

1.

2. DISTRIBUTION 3. TRANSMISSION

12.5/7.2 kV

a.

24.9/14.4 kV

b.

_______ 

kV

c.

_______ 

kV

d.

_______ kV

a.

_______ kV

b.

_______ 

kV

c.

_______ kV

d.

PRESENT SYSTEM

AS OF ___________

LONG-RANGE

PLAN

PART III—SUBSTATIONS AND METERING POINTS

NAME OR LOCATION*

1.

POWER SUPPLIER

2.

3. PRESENT SYSTEM 4. LONG-RANGE PLAN

MVA

a.

kV

PRIMARY

b.

kV

SECONDARY

c.

MVA

a.

kV

PRIMARY

b.

kV

SECONDARY

c.

PART IV—INVESTMENT IN PLANT (Thousands of Dollars )

ITEMS

1.

TRANSMISSION

LINES

2.

ALL

SUBSTATIONS

3.

DISTR. 

TRANSFORMERS

METERS & SERVICES

4.

ALL OTHER DISTR.

FACILITIES

5.

TOTAL 

T&D 

PLANT

6.

GENERAL &

PROD. 

PLANT

7.

PRESENT SYSTEM AS

OF ____________

$0

LONG-RANGE PLAN

$0

RUS FORM 261 REV. 1-95 (CAB 5/96) * Include those furnished by Power Supplier and designate with asterisk.
RUS Bulletin 1724D-101A

Exhibit L

Page 2

REMARKS:

INSTRUCTIONS

A copy of this form is needed for each system planning report. (See RUS Bulletin 1724-101A).

Part I List data as indicated by column headings.

Column 7 (present system) actual experienced peak.

Column 8 (present system). Engineer's best judgment as to system’s capability in terms kWh/mo/cons. as 

determined from his “Analysis of Present System and Basic Data.”

Part II List the mileage breakdown of all distribution and transmission lines in the present system and similar 

data for the long-range plan.

Part III List data for each substation or metering point as indicated in the column headings.

Part IV List investment in plant (dollars) as indicated by the column headings for the present system and for 2 - 3 

- 4 - 5 - 6 for the long-range plan. Investment (dollars) for the several columns are included under the

following accounts:

Column 2—350 + 351 + 352 + 354 + 355 + 356 + 357 + 358 + 359

Column 3—353 + 362

Column 4—368 + 369 + 370

Column 5—360 + 361 + 364 + 365 + 366 + 367 + 371 + 372 + 373

Column 7—Sum of 389 thru 398 + Sum of 310 thru 345 as applicable.

RUS FORM 261 REV. 1-95 (CAB 5/96)
RUS Bulletin 1724D-101A

Appendix 1

Page 1

APPENDIX 1

ECONOMIC CONDUCTOR LIFE CYCLE ANALYSIS

1 BACKGROUND

An Economic Conductor Life Cycle Cost Analysis is a long-term comparison of the costs 

of alternatives available in the construction of distribution lines. As is the case with 

many economic decisions, more initial investment will result in more savings in the long 

term. The goal of this analysis is to identify the best possible combination of initial 

investment and long-term losses reduction. The end product of Economic Conductor 

Life Cycle Analysis is, typically, a graph generated by a spreadsheet showing the Total 

Life Cycle Cost as the Y axis and the Initial Loading as the X axis. See Exhibit E of this 

Guide for an example of such a graph. The graph demonstrates that there are crossover 

points where it is more economical to choose a larger conductor for higher initial loading.

2 COSTS AND ECONOMIC BREAKDOWN

There are many costs incurred due to the construction and operation of a distribution line. 

The goal is to identify the relevant costs that should be compared for an accurate 

evaluation. For example, it is obvious that, for a higher-cost line, there will be more 

annual taxes because taxes are based on value. However, does a larger or smaller wire 

size really result in a measurable difference in annual operation and maintenance 

expense? One of the largest maintenance expenses, right-of-way trimming, would be the 

same for a smaller wire size as it would be for a larger wire size. It is up to the 

cooperative planning engineer to identify and quantify real annual differences for the 

purposes of this evaluation.

Estimated plant life should be based on the best historical information available. In some 

climates, conductor may last more than 30 years. Where growth is a major concern, it is 

possible that—due to reasons such as road widening—conductors may not be expected to 

be in service for more than 20 years. The various components of the analysis will have 

an impact on the outcome and should be reviewed thoroughly.

The value of losses is sometimes a difficult number to derive. It is important to 

remember that you are considering the future value of losses and that historical demand 

and energy charges are usually blended costs of embedded investments. What you are 

considering is the reduction of losses that otherwise would have to be generated from 

tomorrow’s generation plants at much higher rates than embedded, historical costs. This 

will result in the increased value of losses and a trend toward larger conductors.

The key to conducting a successful comparison of life cycle costs is to begin with 

accurate base data. The most important figure is the construction costs of a mile of line 

for a wire size. Very detailed reviews must be conducted to determine the best cost. 

Outliers—conductors evaluated with very high or low costs—that are on the extreme 

ends should be reviewed in detail and possibly removed from the cost development. 

Estimates of construction costs for wire sizes with no history should be carefully 
RUS Bulletin 1724D-101A

Appendix 1

Page 2

estimated. Some determination of additional costs due to larger wire, shorter spans, 

increased pole class, possibly heavier hardware, etc., must be made. Conversations with 

neighboring cooperatives that are using different size conductors would aid in the 

estimation process.

An important item to consider in the evaluation process is that there are two components 

to selecting feeder conductors. Initially, conductor selection is accomplished at a high 

level to pick the few major wire sizes and types to be used for the next 10 to 20 years. 

Once that macro analysis is done, a comparison on a more micro level is possible. It is 

important, after the long-range plan (LRP) is completed, that appropriate segments of line 

are analyzed prior to design and construction. For example, a very long feeder is 

probably not uniformly loaded for its entire length. If the feeder splits after the first mile 

or so into several significantly loaded directions, the first segment should be considered 

separately from the remainder of the feeder or other significant, identifiable segments. 

Due to the ease of use of modern Economic Conductor Life Cycle Cost Analysis 

spreadsheets, this would be a very prudent exercise.

There are a number of Economic Conductor Life Cycle Cost Analysis spreadsheets or 

programs available. Generally, the differences lie in respect to the level of detail they 

offer. For the purposes of this Guide, a standard Economic Conductor Life Cycle Cost 

Analysis spreadsheet will be reviewed.

3 VARIOUS CONDUCTOR TYPES

A brief review of common aluminum conductor options is presented below. When 

accomplishing an LRP and a conductor alternative study, a more detailed consideration 

of the available types of conductor should be considered. There are distinct advantages 

and disadvantages to using certain conductor types and sizes under different local 

conditions. For some areas of the country, conductors with high tensile strength or 

reduced vibration are more advantageous because of longer spans or terrain. Some 

situations may require conductors with increased conductivity and thermal ratings. Some 

areas may require higher corrosion resistance. These localized and specific requirements 

must be considered and weighed during the selection process.

Key conductor types being manufactured today are:

All-Aluminum Conductor (AAC). AAC conductor is a high conductivity cable that 

consists of aluminum wires concentrically stranded. Generally this conductor is preferred 

in heavily loaded urban areas where short spans and high current levels exist. The 

aluminum used is a compound known as 1350-H19, which has a good combination of 

conductivity and corrosion resistance.

Aluminum Conductor, Steel Reinforced (ACSR). ACSR has been the standard for 

overhead distribution and transmission conductor for years. It has a good combination of 

strength and ampacity. The conductor consists of a steel core surrounded by layers of 
RUS Bulletin 1724D-101A

Appendix 1

Page 3

aluminum (1350-H19). Higher strength is achieved by increasing the number of steel 

support core wires for use in transmission systems or particular distribution applications 

of extremely long spans. An advantage that ACSR has over AAC is that the steel core 

decreases the sag of the conductor and allows a higher thermal rating to be achieved for a 

particular span length. The steel also increases the strength of the line providing greater 

resistance to ice and breaking problems.

All-Aluminum Alloy Conductor (AAAC). AAAC was designed to compare favorably to 

ACSR in strength to weight and in ampacity. The wires within the conductor are an 

aluminum alloy (6201-T81) developed to be stronger than the 1350-H19. The biggest 

advantage that AAAC has over ACSR is that it is much more corrosion-resistant and 

abrasion-resistant. Because of this, it is particularly beneficial along coasts or corrosionprone areas.

Aluminum Conductor, Aluminum-Alloy Reinforced (ACAR). ACAR is a conductor that 

consists of separate strands of the aluminum alloy (6201-T81) found in AAAC along 

with 1350-H19 aluminum strands. There are a number of different configurations for the 

same wire size to optimize ampacity or strength for a given application.

Specialized Conductors. There are a number of other special configurations and 

materials available to address specific problems, such as vibration, increased tensions, or 

other concerns. These are typically very specialized products and outside the scope of 

this manual. However, it is worthwhile to research and evaluate these conductors to 

address certain needs.

4 CONCLUSION

Selecting and standardizing on a selected few conductor types is a key responsibility of 

the distribution planning engineer. Typically, two or three types of conductors are 

chosen: one for lightly loaded single-phase and three-phase lines, one for mediumloaded three-phase lines, and one for heavily loaded and main substation tie lines. The 

key factor in making the decision is economics. However, the operational control 

function of conductor availability is also another key factor. Each conductor evaluated 

for economics must be evaluated for availability. Each electric system experiences 

environmental conditions and land attributes that have to be considered for rebuilding and 

conductor availability. These conditions vary but can be summarized as follows:

• Coastal atmospheres with high corrosive attributes,

• Ice storms,

• Tornadoes,

• Hurricanes,

• Earthquakes,

• Flooding, or

• Mountainous terrains.
RUS Bulletin 1724D-101A

Appendix 1

Page 4

The above list is in no way complete and inclusive, but does highlight the factors the 

electric planning engineer needs to consider when selecting conductors for line 

construction.
RUS Bulletin 1724D-101A

Appendix 2

Page 1

APPENDIX 2

RADIAL TRANSMISSION LINE RELIABILITY AND OPERATIONAL ASSESSMENT

1 BACKGROUND

A radial transmission line serving distribution substations is defined as distribution 

delivery point(s) served by a transmission line system that does not have any other means 

of transmission service. If there is a failure of the transmission line, there is a resulting 

power outage to the substation (or substations) until the line is repaired. A service 

reliability study will indicate areas of the system which need special attention and may 

even indicate the general type of work which will be most cost-effective in correcting 

such service deficiencies. If the transmission supplier is responsible for an excessive 

amount of the outage time (typically, more than one consumer-hour per consumer/year 

averaged or trended over five years), this should be noted. The transmission supplier 

should be requested to provide comparable outage analyses for all similar delivery points.

Reliability should be based on standards or criteria established by the cooperative or 

other national organizations. A service reliability standard provides a basis on which 

management can evaluate system performance. Please see RUS Bulletin 1730A-119 

entitled “Interruption Reporting and Service Continuity Objectives for Electric 

Distribution Systems” for further details regarding RUS service reliability polices. Also, 

the system planner should be fully aware of the transmission line reliability policies and 

indices as required by the Federal Energy Regulatory Commission (FERC) as 

administered by the North American Energy Reliability Council (NERC). Most 

FERC/NERC guidelines deal with the bulk transmission grid; however, they do have an 

impact on the reporting that each power supplier is required to file.

The importance of service reliability should be reflected in the long-range system plan. 

Because of wide differences in operating conditions and local requirements, RUS does 

not attempt to specify a service reliability standard for all systems. However, each 

borrower should adopt a standard, which will serve as a goal in the development of its 

system. The five consumer-hours per consumer per year interruption rate used for loan 

applications should not be considered as a goal. Rather, system goals should be nearer 

one hour for suburban and two hours for rural consumers. Furthermore, it should be 

recognized that, except during truly unusual major storms, consumers are not concerned 

with the source of an interruption. Whether the power is off only for their individual 

transformer or because of a power supplier’s interruption makes little difference to the 

consumer. Thus, all sources of interruption should be considered for possible 

improvement in service reliability.

The need for improvements to radial transmission lines can be separated into two 

different categories: performance and exposure. Addressing a radial transmission line’s 

performance can involve significantly different factors than addressing a similar line’s 

exposure. For example, improving ROW or adding lightning arrestors are good 

approaches to improving performance; however, they do nothing to reduce exposure. By 
RUS Bulletin 1724D-101A

Appendix 2

Page 2

the same token, providing an alternate transmission source may improve SAIDI metrics 

but momentary outages and frequency of outages will remain unchanged unless the 

alternate transmission source becomes the primary source.

Whether the transmission lines are owned by the distribution system or the transmission 

supplier, planning should be approached on a “one system” concept. Excessive costs for 

transmission facilities cannot be justified by minor savings on one part of the system. The 

converse is also true that excessive distribution plant should not be constructed simply to 

avoid transmission construction. The economy of radial-feed substations should be 

weighed against the reliability of loop-feed substations. The applicability of each design, 

as it pertains to the basic system design and established operating practices, should be 

carefully considered.

To aid in such an assessment, the following procedures and the attached form have been 

created. With the planning engineer and all associated parties working together to 

complete the factual data required, all pertinent conditions can then be assessed. By 

answering the questions listed with a clear yes or no, needs can be established and all 

parties can agree that long-range plans should attempt to satisfy those needs. If many of 

the questions are answered in the affirmative, clear reliability concerns are present and 

system improvement options should be reviewed under the “one-ownership” concept to 

identify the economics for improved reliability of each option.

2 PROCEDURE

The general process for accomplishing the assessment is as follows:

1. The transmission line provider and cooperative/distributor are to review the current 

radial electric power delivery system and identify any weak links that involve 

significant load requirements. (Note: The transmission and substation provider and 

cooperative/distributor may be the same entity). A weak link is identified as a system 

configuration that has recently contributed to an extensive unplanned outage and/or a 

condition that would require a lengthy outage in order to accomplish extensive 

maintenance. Radial transmission lines without backup or looping options are prime 

components that need to be reviewed. It is not the intent of this assessment to review 

and evaluate every radial transmission line in the cooperative/distributor’s service 

area, only those lines that have recently presented a problem or have significant 

current or future high load conditions.

2. After identifying the weak links, factual data is to be accumulated by the transmission 

line provider and cooperative/distributor, and tabulated on the attached form. After 

tabulating the factual data and answering the questions, the number of affirmative 

answers can be counted.

3. If there are a number of affirmative answers tabulated, long-range planning should 

include the review of economical ways to improve and/or eliminate the weak links.
RUS Bulletin 1724D-101A

Appendix 2

Page 3

4. After a thorough review of possible solutions using the “One Ownership” method, the 

cooperative/distributor can decide which options, if any, should be included in its

long-range plan. The attached form can be used as a general tool for documenting 

what is to be included in the new LRP and why. It is not to be considered an official 

commitment document for system improvements. It is only a tool for communicating

with the various electric system owners. It is further understood that agreement to 

include the weak link in the planning process in no way commits any party to 

construct the system improvement required to resolve the weak link.

5. After an economic review of the options has identified that the weak link can be 

eliminated or improved in the long range, all system parties/owners should commit to 

planning those system improvements. If they cannot, all parties agree to live with the 

weak link and work around it as conditions dictate.

3 MEANING OF TERMS (Listed in Form Order)

The terms used in the Radial Transmission Line Reliability and Operational Assessment 

form are defined as follows:

T/L #. The designation given by the long-range system study for the Transmission Line 

(T/L) under consideration.

Transmission Line Description. A short phrase that defines clearly the T/L under review.

Operating Voltage. The phase-to-phase nominal operation voltage of the line.

Conductor Size and Type. Denotes the wire size and type. Including the “word code”

would be very helpful. An example is “336 kcmil ACSR (Linnet).”

Right-of-Way Width. Denotes the available width of ROW in feet.

Radial Distance. The length of the T/L from the bulk feed or looped line to the 

cooperative/distributor’s delivery point, recorded in miles. If more than one delivery 

point is associated with the radial line, the line distances between each delivery point are 

to be determined and recorded.

Peak Load. The maximum non-coincident peak electric load is the highest ever 

experienced on the system or, at least, over the last 12 months, expressed in megawatts 

(MW). If there is more than one delivery point associated with the radial line, the peak 

loads are to be tabulated for each delivery point.

Last Peak Time. The month and year of the last peak load is identified.

Load Distance Service Factor (LDSF). This is the arithmetical product of the radial T/L 

distance (in miles) times the last peak load experienced on the line (in MW). The LDSF 
RUS Bulletin 1724D-101A

Appendix 2

Page 4

is recorded in MW-miles and is a numerical value for the planning engineer to assess the 

criticalness of electric load to a distance of T/L. The factor really has no real meaning 

and is to be used only as a guide for assessing the need for system improvements and T/L 

looping. If there are multiple substations or delivery points served by the T/L, an LDSF 

is to be calculated for each point, including the total load being served from and through 

that delivery point.

Transmission Line Provider. The organization that has responsibility for planning, 

maintaining, and operating the T/L under review.

Cooperative/Distributor or Cooperative. Refers to the organization that distributes power 

from the delivery point that is served by the radial T/L.

Significance of MW-Miles. Planning engineers in the T/L and distribution business have 

generally agreed that, when radial transmission line loading reaches an LDSF greater 

than 100 to 150 MW-miles, efforts should be included in system long-range planning to 

look for ways to reduce the radial exposure. This should be considered only a guide and 

not a mandate in system long-range planning.

Poorly Accessible T/Ls. Refers to T/Ls that have rights-of-way (ROW) that, for 

whatever reason, are not readily accessible during a significant part of a given year. 

Reasons for inaccessibility could be, but are not limited to, the following: ROWs that are 

very swampy and subject to rainy seasons; ROWs that are mountainous and subject to 

snow or icy conditions during parts of the year; and ROWs over waterways with T/Ls 

built off pilings or piers.

High-Priority Loads. Distribution loads served by the cooperative/distributor that would

experience severe uneconomical or life-and-death conditions if an extensive outage 

occurred. Typical loads that would experience such could be hospitals, 

industrial/manufacturing plants, airports, commercial loads, large oil and gas pumping 

loads, etc. Service areas where consumers rely heavily on electricity for heating could,

likewise, be considered a high-priority load.

Conductor Condition. Occasionally, T/L providers perform sample testing on very old 

(i.e., more than 30 years) conductors to see if their condition is suitable for further longterm use. If conductors are found to be in reasonably good condition (e.g., they are not 

brittle or prone to breaking, the steel core is not rusty or missing, etc.), then they can 

continue in use. If, however, such is not the case, replacement or repair of the Radial 

Transmission Line (RTL) needs to be included in the long-range planning process.

Three Outages Over Last Two Years. T/Ls that have experienced more than one outage 

per year over the last two years due to poor line hardware indicates poor and depreciated 

equipment conditions and are in need of replacement and/or improvement that should be 

included in long-range planning.
RUS Bulletin 1724D-101A

Appendix 2

Page 5

Four-Hour Outage Within 12 Months. A four-hour outage can be critical for many 

distribution loads and must be considered when long-range planning takes place. T/Ls 

having such operational conditions with a high LDSF should be reviewed in the system 

long-range planning process.

Unreliable Line Percentage. FERC requires that T/L providers identify the reliability of 

all their lines and rate them in order from least to most reliable. With such information, 

the power supplier or transmission line provider can quickly tell if the radial T/L under 

review is within the top 5% of most unreliable lines on their system. If it is, it is 

important that system improvements be reviewed in long-range planning.

Loaded >50% Capacity. Radial T/Ls projected to be peak loaded over 50% of published 

full load capacity should be evaluated for long-range system improvements, especially 

for lines operating at ≤ 69 kV. Published capacity denotes the manufacturer’s rating,

typically with conductor at 75oC, ambient temperature at 25oC, emissivity at 0.5%, wind 

at 2 feet per second, and the conductor in direct sunlight.

Operating Voltage ≤ 69 kV. Radial T/Ls operating at subtransmission voltage levels can 

have high line losses and voltage drops when heavily loaded and are not good for bulk 

feed looping. Such voltage levels do not directly impact system reliability but do impact 

system operations and economics. Also, such voltage lines are weak for transformation 

to 25 kV distribution. As a result, such lines are a good place for possible system 

improvements or changes within the surrounding service area.

4 RADIAL TRANSMISSION LINE ASSESSMENT FORM

The form below is for assessing the reliability of radial transmission lines. It can be 

duplicated for as many radial T/Ls as the power supplier, transmission line provider,

and/or cooperative/distributor identify as needing review. Electronic or Excel® versions 

can be acquired from the NRECA T&D System Planning Chair and the Staff Director of 

the RUS Electrical Engineering Branch.
RUS Bulletin 1724D-101A

Appendix 2

Page 6

Radial Transmission Line Reliability and Operational Assessment

Radial Transmission Line (RTL) Characteristics: RTL #:__________

Name and Description: __________________________________________________________________

Operating Voltage (kV): ___________________ Conductor Size & Type: ________________________

Right-of-Way Width (feet):_________________ Radial Distance (miles): ________________________

Last Peak Load (MW):_____________________ Peak Time (month, year): ________________________

Load Distance Service Factor (MW-Miles):A _______________________ Year Built: _______________

With loss of the RTL, what % of load can existing distribution ties support? ________________________

Major Line Maintenance Cycle Years: ____________

Year of Last Major Line Maintenance: ____________

Right-of-Way Location (cross-country, roadside, etc.): _________________________________________

Right-of-Way Maintenance Cycles (years): ____________

Frequency of Right-of-Way (years):

Inspections ______________ Mowing/Spraying ______________

Danger Tree Removal ______________ Side Trimming ______________

Transmission Line Provider:______________________________________________________________

Impacted Distributors or 

Cooperatives: ______________________________________________________

RTL Reliability and Operational QuestionsB No Yes

1. Does the RTL have a high Load Distance Service Factor (LDSF) greater than

150 megawatt-miles? ___ ___

2. Is the RTL poorly accessible as determined by the Owner during all or part of the year? ___ ___

3. Does the RTL serve a delivery point that provides power to high priority loads 

(e.g., hospitals, manufacturing parks, airports, commercial loads, etc.)? ___ ___

4. Is the conductor in deteriorated condition based on recent sample testing? ___ ___

5. Is the RTL condition contributed to more than three sustained outages over the 

last two years? ___ ___

6. Has there been an outage over four hours in the past five years attributed to 

the RTL (excluding those during a major storm)? ___ ___

7. Is the RTL in the power supplier’s top 5% of most unreliable lines? ___ ___

8. Does the RTL owner have any major improvement plans in the near future or in 

the general area of the distributor/cooperative substation? ___ ___

9. Is the RTL operating at 69 kV or less and have a >50% of the conductor published

full load amperes for the projected long-range peak loading conditions? ___ ___

Number “Yes” ResponsesC = ___

RTL PLANNING COMMITMENT

Based on the above assessment, the electric system distribution engineer has decided that the referenced 

RTL ________ is or _______ is not to be included in the new electric system long-range plan. A copy of 

this assessment and commitment is to be supplied to the RTL provider indicated above.

Signature: ________________________________________

Distributor’s Planning Engineer Name: ________________________________________

Distributor’s Planning Engineer Title: ________________________________________

A Load Distance Service Factor = (Latest Peak Demand Load Served) × (Radial Line Distance) B Categories shown in italics are to be answered by the RTL Owner and Provider, if applicable. C RTLs that have a number of “affirmative” responses to the reliability and operational questions above should be included in the long-range 

planning process.
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APPENDIX 3

AGING CONSIDERATIONS FOR LONG-RANGE CAPITAL EXPENDITURES

A cooperative needs to balance capital expenditures across all parts of its system to maintain an 

acceptable level of service for all consumers. This appendix addresses the challenges that arise 

when all or part of the system is experiencing stagnant growth or declining loads, including the 

issue of allocating available funds between growth and non-growth areas.

The problems commonly encountered in aging, low-growth distribution systems can be 

described as follows:

• Deteriorated poles, crossarms, etc. > 35-50 years old

• Deteriorated and obsolete conductors (copper-clad and aluminum) > 40 years old, 

especially those with excessively long spans and aging conductors

• Deteriorated and obsolete substations (wooden structures)

• Deteriorated and obsolete substation transformers

• Deteriorated transmission lines (34.5 kV, 46 kV)

• Deteriorated reclosers and switches

• Deteriorated voltage regulators and regulator controls

• Excessive electrical losses (primary, secondary, and transformer)

• High levels or unknown levels of PCBs in power and distribution transformers

• Deteriorated concentric neutral underground cable where the neutral is corroded away

• Inadequate or ineffective lightning protection

• Inadequate or ineffective grounding, causing excessive stray voltages

• Inadequate sectionalizing and overcurrent protection

• Deteriorated knife blade switches

• Deteriorated and improperly maintained reclosers

• Deteriorated insulators causing excessive radio noise

• Deteriorated Air Break Switches out of adjustment or inoperable due to corrosion

• Insufficient grounding and insufficient lightning arrestors

• Rusting equipment enclosures (especially pad-mounted equipment)

• Obsolete SCADA system (no spare parts or support)

• Obsolete two-way radios (no parts available)

• Obsolete microwave systems (no spare parts available)

Outage Criteria

Cooperatives are expected to provide improved outage reliability and power quality to their 

members. Sectionalizing schemes and equipment used 20 or 30 years ago will usually not be 

acceptable to today’s electric consumer. Reliability suffers even further when the distribution 

system begins to deteriorate. The cooperative’s management and engineer must determine the 

reliability requirements that their membership expects and plan accordingly.

System Losses

System losses are a substantial financial drain on any system, and the average cooperative has 

losses in the hundreds of thousands of dollars every year. The cooperative should track losses by 
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substation on a monthly and yearly basis in order to identify problems in different parts of the 

system. While losses are a costly part of system operation, they also present an opportunity. 

Reducing losses reduces overall costs. 

The continued use of small, aging conductors can contribute substantially to losses.

Underground Cable is one of the many troublesome spots on an aging system.

• High Molecular Weight (HMW) cable has proved to be very unreliable and should be 

replaced as soon as possible

• Bare concentric neutral cables are often found to have neutral conductors that are 

badly corroded or completely gone, which causes numerous operating problems.

• Non tree-retardant cross-linked polyethylene cables (XLPE) begins to have a high 

rate of failure as it ages.

The location and quantities of these types of underground cables should be recorded and 

evaluated for failure rate and plans made for their possible replacement.

Old and Depreciated Transformers

• Does the cooperative have any old 1.5 kVA, 3 kVA, 5 kVA, or possibly any 7.5 kVA 

transformers still in service? Check the continuing plant records (CPR) or mapping 

records.

• Are there any PCB transformers or capacitors or substation PCB transformers left?

These may need to be replaced after checking the kWh/kW usage, etc.

Rights-of-Way

Right-of-way (ROW) problems can be a significantly costly item as well.

• How many miles of right-of-way that need to be cleared periodically?

• Are the ROWs in worse condition in the slow-growth areas?

• How many miles were cleared, cut, or mowed last year?

• How many years will it take, based upon past performance, to clear ROWs on the

entire system?

– Determine the optimum clearing cycle based on the differing growth rates of 

vegetation in the area.

Recloser Maintenance

• Are the operations counters on all reclosers regularly recorded?

• Is a formalized maintenance plan in place? Old, poorly maintained reclosers will 

seriously reduce system reliability.

• Are sectionalizing studies up to date?

Electronic Recloser/Breaker Maintenance

• Electronic recloser controls and breaker relay should be regularly tested.
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• Old, obsolete units should be replaced. These controls are usually used in substations 

and main feeders, and have the largest impact on the proper operation of the system 

sectionalizing scheme.

Voltage Regulators

• Are operations counters read regularly?

• Has the number of operations exceeded manufacturers’ recommendations, typically 

20 years or 1,000,000 operations (see manufacturers’ recommendations)?

• Can the regulator stand the available fault current if a fault occurs? In general, this is 

40 times the nameplate ampere rating of the regulator for a time period of 0.8 

seconds.

Pad-Mounted Equipment

Maintenance issues with transformers, switchgear and other pad-mounted equipment can be a 

big expense to the cooperative.

• Structural problems are the predominant failure mode.

• Rust and corrosion are a major concern.

• Oil leaks can also occur.

• Routine visual inspection is required (see CRN Report #98-11, entitled Motor 

Problem Resolution and Avoidance, for further details).

Aging Conductors

Given the fact that overhead electrical conductors have an average life expectancy of 

approximately 50 years, it is clear that many original distribution lines are approaching the end 

of their useful life span. (See CRN Report #00-31, entitled Guide to When to Replace 

Distribution Line Conductors, for additional details.) Conductor replacement should be strongly 

considered with a pole replacement program, to avoid the wasteful expense of setting new poles 

in a line with old conductors.

Some of the commonly used original conductors are as follows:

Size Type

App. Ampere

Capacity

Rated Breaking Load 

(lb.) NEW Conductor Weight (lb./mile)

2A Copperweld-Copper 240 5,876 1,356

4A Copperweld-Copper 180 3,398 853

6A Copperweld-Cooper 140 2,585 536

8A Copperweld-Copper 100 2,233 392

9-1/2 D Copperweld-Copper 65 1,743 298

3 #12 Copperweld 90 2,236 289

Some of the more common reasons why conductors fail include:

• Ice loading that exceeds maximum conductor tension;
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• Long spans with ice loading, resulting in elastic stretch;

• Arcing damage from trees, lightning, wind, etc.;

• Surface corrosion on copper-clad conductors that leads to steel corrosion;

• Electrolytic corrosion due to galvanic action;

• Surface corrosion and inner corrosion of the steel strand on aluminum conductors;

• Loss of zinc coating on steel core wires (ACSR conductors);

• Fatigue failure due to wind-induced vibration; and

• Annealing due to excessive electrical current (hard-drawn copper wire).

Record Keeping on Conductors

It is very helpful to keep detailed records when conductors fail, including the reason for the 

failure, , size of conductor, condition of conductor, approximate age, span lengths, etc. A 

database should be created and maintained detailing conductor failure by substation, by circuit, 

and by geographic area.

Inspection Provisions

The inspection provisions are contained in the 2012 National Electric Safety Code (NESC), 

Section 214. A good inspection program is intended to identify areas or equipment that need 

maintenance or replacement. Maintenance must be done a regular basis to keep up with the 

inspection process, otherwise the process breaks down and system reliability suffers. 

Maintenance and inspection programs should be part of the planning and budget process to 

insure that adequate funds are available to maintain the programs.

RUS Bulletin 1730-1, Electric System Operation and Maintenance (O&M), includes more 

detailed directions on the inspection process. It is important to keep in mind that line patrol is 

usually carried out while walking, riding or flying a line to look for obvious right-of-way or 

pole-line condition problems. Line patrol does not usually involve a detailed pole-by-pole 

inspection to find loose hardware, cracked insulators, etc. While a detailed line inspection 

program would be the ideal, it generally proves too slow and costly to allow for regular, 

economical maintenance and upkeep of the distribution system. However, the use of radio 

frequency interference (RFI) and/or infra-red detection equipment during line patrol may detect 

conditions such as loose connectors and cracked insulators that may otherwise be missed.

Voltage Drop

One of the classic problems associated with small conductors used with older lines is excessive 

voltage drop. All distribution systems should have their engineer regularly perform a 

distribution voltage drop study (usually done as part of a construction work plan) to insure that 

parts of the system are not experiencing excessive voltage drop. The results of the voltage drop 

study will identify overloaded conductors and areas with low voltage that may require 

reconductoring or the addition of voltage regulators.

Distribution System Model Discrepancies

In order to effectively perform a distribution voltage drop study, the system model must be 

reasonably accurate. Older low-growth systems often find that errors have crept into their 

models over the years, such as:
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• Line sections are of wrong length.

• Mixed conductor spans are entered into the database as the largest conductor (i.e., 

1 #6, 1 #8, 1 #4, with an 8A neutral is listed in the model as 3-phase, 4 CU).

• Regulators and capacitors are missing or listed in wrong locations.

Process for Formulating an Engineering Solution

1. Quantify the problem by making a list of all known system deficiencies in the 

slow-growth areas.

2. Quantify the number of consumers that would be affected by an outage on a 

particular section of line.

3. Estimate costs to repair/replace each item based on current costs.

4. Prioritize the list of problem areas based upon one or more of the following 

subjective criteria using good engineering judgment:

(a) Cost/benefit ratio

(b) Outage reduction

(c) Improved losses

(d) Reduced liability

(e) Improved operational flexibility

(f) Improved safety

(g) Fewer consumers affected by an outage

5. Examine the current work plan in the following areas:

(a) Quantify proposed investment in slow-growth areas.

(b) Review RUS Form 7 (year-end) of completed work orders and determine 

how much investment in slow-growth areas was added to plant over last 

year.

(c) Compare these two numbers to determine the extent of the problem. If the 

work order amount spent in low-growth areas last year is relatively low 

compared to the proposed improvements in that area, then the capital 

budget will have to be substantially increased to pay for the needed 

improvements.

6. Determine the number of poles and amount of line that needs to be replaced.

(a) Approximately 20 poles/mile × miles of line = number of poles on the 

system.

(b) Review CPR records of poles. How do they compare?

(c) Estimate the average age of the poles on the system. It is best if the 

average age can be broken down by substation area.

(d) How many were inspected and treated with a ground line treatment, if 

needed?

(e) How many years will it take to completely inspect the system at last year’s 

inspection rate, and is that time frame acceptable considering the average 

decay rate in the region. How many poles were replaced last year?

(f) Determine cost/benefit or payback period on treating poles.

(g) A plan should be put into place to have poles replaced by the end of a 

reasonable life expectancy.
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(h) Quantify how many miles of copper/copper-clad line are still in service. 

Check the CPR records, the engineering model, and the system maps. 

Most copper lines are at least 50 years old.

(i) It is good practice to remove all steel lines as soon as practicable.

(j) Is there a current plan to replace copper/copper-clad line? Copper 

replacement programs should be budgeted and approved in a construction 

work plan.

(k) It is usually most practical to replace portions of the copper lines each year 

according to a prioritized list. It is recommended that systems replace all 

small 1-phase or V-phase copper distribution lines within the next 10 

years or less, depending upon their condition and the outage experience on 

the specific line.

Balancing Capital Needs

1. Examine the current construction work plan to see what percentage of the total 

dollars in the work plan is budgeted for replacing aging plant (usually classified in 

the work plan as ordinary replacement).

2. After quantifying the extent of the aging problem, determine the timeframe in 

which remedies have to be made and, therefore, how much capital needs to be 

budgeted to ordinary replacement on a yearly basis.

3. Compare new investment dollars per consumer in the various areas of the system 

or by substation.

4. Depending upon the age and condition of the system, 10 percent to 30 percent of 

the total annual work plan budget may be earmarked for aging plant problems. 

Experience has shown that older, low-growth, high-equity systems are often not 

in very good condition either physically or electrically.

5. An electric utility business requires continuing capital investment supported by 

carefully managed depreciation and capital addition programs. Judicious use of 

borrowed funds for physical plant that will last at least 35 years is a prudent 

financial practice.

Summary

The cooperative should:

1. Develop a detailed list of all known system operation and maintenance problems. 

All systems are not the same, and the problems will vary according to terrain, 

climate, and electrical load patterns.

2. Quantify the remedies in dollars, man-hours, capital expenses, etc.

3. Prioritize the remedies based upon the criteria outlined above.

4. Budget funds for the highest priority items.

5. Construct the facilities as planned through construction work plans.

6. Update the aging plant area list, and re-prioritize and re-budget yearly or during 

work plan cycles.

7. Follow through with the plan, and complete the needed replacement. Failure to 

address these issues in a timely manner is likely to have grave financial 

consequences.
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APPENDIX 4

DISTRIBUTED GENERATION IN LONG-RANGE PLANNING

1 BACKGROUND

In 1936, when the Rural Electrification Administration was created by the U.S. Congress, 

Distributed Generation (DG) was not even on the radar screen. In fact, for most rural 

areas, electricity was only a wish and a hope for the future. Of approximately 6.3 million 

farms at that time, only about 205,000 were receiving centralized electric service. By the 

early 1970s, about 98% of all farms in the United States had electric service—quite a 

success story for the REA program. Where there is vision and economic technology, 

lives change for the better. Such is thought of DG. Technology is changing very fast in 

this area and DG is expected to have significant impacts on electric power distribution.

Since technology, operating standards, and economics are not quite ready for broad 

applications of DG systems, why then include such a topic in a Long-Range Planning 

Guide? It has been included to challenge electric distribution planners for what is to 

come and for them to acknowledge that the technology and economics are there for some 

applications today.

With the high costs of large generating plants, transmission lines, substations, and 

distribution lines, we all need to be looking for alternative methods to providing electric 

power to our customers in the most economical method available. DG may fit that 

situation in some circumstances even today and the planning engineer needs to consider 

all resources that are available.

There are several different types and applications of distributed generation and they are 

listed as follows:

• Large-Scale,

• Medium-Scale,

• Small-Scale, and

• Residential/Commercial Solar PV.

Each category is summarized below to aid the system planner in identifying how and 

when DG could be applied.

2 LARGE-SCALE (500 kW–10 MW) DG (Industrial)

In general, application of large-scale DG systems will require some level of detailed 

engineering. These relatively large distributed generators will likely have a significant 

impact on long-range planning, particularly the larger applications. Many large-scale 

distributed generation applications have been implemented over the last several years, 

and many were cost-justified through the application of rate incentives, such as peak 

shaving, reserve or dispatchable capacity, and real-time or market-based pricing.
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Recent, significant increases in fuel costs have brought into question the economic 

feasibility of many of these generators as long-range solutions. Volatility in both natural 

gas and diesel fuels, common fuels for this scale DG, has significantly reduced the costeffectiveness of these applications. However, there are still significant potential savings 

with this size DG project in certain applications, particularly where load growth or shortterm peak loading conditions require significant capital investments. Additionally, 

overall reliability of a feeder or transmission segment can be improved, when normally 

served by a radial source, if the generator is located near the load. Other considerations

—such as tariffs, rate restrictions, all-requirement contracts, fuel costs, environmental 

impact, and O&M requirements—should also factor into the decision-making process. 

Generators of this size should at least be considered in some of these special cases as 

alternatives to capital-intensive projects, particularly reliability-based ones.

Similar considerations will have to be given to the ever-popular renewable resources, 

particularly wind power. Wind farms will likely be the quickest large DG applications to 

impact system planners. Today, most wind farms are larger than 10 MW; however, as 

popularity rises and costs decrease, there will be increased pressure to move to small 

wind farm applications. The biggest design factor of this size system will be its “backfeed” capability. In renewable-rich areas, and with proper incentives, there is the distinct 

possibility that these renewable sources may exceed local demand. In this case, the 

system planner must also consider line and equipment capacities and ability to manage 

bi-directional load flow on a day-to-day or hour-to-hour basis.

From strictly a planning perspective, the system planner will have to seriously consider 

the availability and predictability of renewable DG energy sources. Although renewable 

resources—such as wind and solar—are great at off-setting energy produced by burning 

fossil fuels, the variability in the “fuel” availability will be a challenge, particularly the 

farther out on the distribution system these medium DG sources are located. It is very 

likely that renewable resources can only be used to off-set or delay capacity 

improvements when they are combined with near real-time smart grid applications, such 

as load shedding.

3 MEDIUM-SCALE (50 kW–500 kW) DG (Commercial)

This DG size is probably the most commonly available engine-generator set today. They 

are quite common in many commercial and some industrial applications. Industries 

highly dependent on electrical power, and often required by law or economics to have 

generator backup, make up a considerable aggregated DG capacity base. Hospitals, 

prisons, fire protection, casinos, and even hotels often have full or near-full capacity 

generation on-site. In the late 1990s, there was a significant effort by the industry to 

utilize this unused capacity. Although there are successful projects utilizing mediumscale DG, deployment has not reached projections because of several hurdles, including 

the following:
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• Limited rate support;

• Increasing fuel costs;

• Limited G&T price signaling;

• Limited communications and system control functions between the DG owner and the 

utility for large-scale assimilation with the distribution system;

• Equipment costs, especially for paralleling switchgear;

• Service interruption on lower cost, break-before-make transition switchgear; and

• Operation and Maintenance cost and expertise.

As in large-scale systems, medium-scale DG may be able to delay capital-intensive 

improvements, but more likely on a distribution system level, provided that the DG 

source is very reliable. If a DG system is going to be included as a solution for a 

distribution system limitation, the system planner may need to require that the DG be 

directly assigned to interruptible loads. Otherwise, system performance may fall outside 

of acceptable ranges.

Application of medium-sized renewable DG sources will likely lag behind large-scale 

DG sources by a few years. However, if economies of scale apply to the manufacturing 

of renewable products, then medium-sized applications will become more commonplace. 

In renewable-rich areas, the aggregate of medium-sized DG projects on a feeder, in 

effect, may become similar to a large-scale DG source. In this case, many of the largescale DG issues apply. If only one or two medium-sized renewable DG sources are 

located along a distribution feeder, then the traditional DG considerations above will 

apply, with one likely caveat. Most renewable DG applications require grid power for 

excitation of the generator, and they will most likely require parallel operation. Parallel 

operations with the grid—even in medium-scale applications—creates a host of new 

design considerations, particularly with respect to bi-directional load flow, voltage 

regulation, and sectionalizing.

4 SMALL-SCALE (1 kW–50 kW) DG (Residential)

Small-scale DG is currently very limited. Most DG of this size will be either residential 

or small commercial applications. In general, these applications operate more as a load 

off-set or reduction rather than as a generation source. Renewable energy applications 

such as solar are the most likely candidates in this category. To date, there has been more 

debate than deployment on these DGs, although popularity continues to rise. Most 

current solar applications interface via an inverter, which monitors the distribution system 

for outages and turns off in the event of a grid outage.

With the adoption of IEEE and UL standards, there is less and less operational and 

sectionalizing concern over these small DG applications, although the debate is not over. 

It will take a significant penetration of these DG applications to have a significant impact 

from a system-planning perspective. If anything, there will be more of a financial impact 

from small-scale DG applications since they are effectively reducing load. As with other 

recently set goals—such as energy efficiency and inclining block rates—small-scale DG 
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will have more of an impact on the load projection aspect of system planning. Again, the 

biggest factor of concern is the predictability of the impact of the small DG or other loadreducing smart grid application.

As an example, an area may exist on a feeder where solar panels are installed on all new 

houses. On a normal, warm, sunny day, solar panels would likely offset a considerable 

amount of air conditioning load. However, an event as simple as a cloudy weather front 

moving through would immediately reduce solar output, producing an aggregate affect 

equivalent to cold-load pickup since there would be considerable lag in the thermal 

response of the homes cooling down from the cloud cover. Given that battery storage is 

considerably more expensive and maintenance intensive, it is less likely that energy 

storage will be implemented with early residential inverter systems.

Again, the system designer must take into consideration the impact of even small DG 

effects on the distribution system when they are adopted on a large scale. Incentive 

programs pushed by federal mandates may accelerate the deployment of such systems. 

Federal mandates such as renewable portfolio standards appear to have little to do with 

economics and may, in fact, impact even distribution planning sooner than expected.

5 RESIDENTIAL AND COMMERCIAL SOLAR GENERATION

One of the greatest potentials for distribution system and power supply is the 

development of small solar generators less than one megawatt in size. In most of the 

United States, there is very good availability of solar energy during peak summer times. 

Extensive addition of solar generators by residential and commercial consumers would 

reduce the requirement for new large generator construction, as well as reduce major 

improvements on distribution systems (e.g., major three-phase circuit rebuilds, substation 

upratings, etc.). Currently, power suppliers are realizing such potential and are 

developing generation purchasing policies that will pay solar generator installers from 12 

to 20 cents per kilowatt-hour with contracts lasting up to ten years. As more and more 

power suppliers realize this potential, the addition of solar generators will greatly impact 

distribution system planning and will need to be considered when evaluating future 

capital requirements for long-term electric system needs.

The key to the situation is the quality, reliability, and costs of the equipment being 

manufactured. If quality and reliability can be assured by industry and governmental 

long-term warranties, and if costs continue to decline as the demand for such generation 

occurs, the solar generation option will play a very important role in future planning of 

electric distribution systems.

6 CONCLUSION

As technology expands and economics drives the market, DG is sure to have an impact 

on electric power distribution in the very near future. As constraints continue in the 
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building of more large generating plants, transmission lines, substations, and distribution 

lines, DG is sure to become more and more economical.

Power suppliers and distribution cooperatives are encouraged to work closely together to 

develop policies that will encourage this renewable resource, one which will contribute 

significantly to the reduction of capital funds to increase system capacity as the demand 

for electric energy grows.
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APPENDIX 5

BIBLIOGRAPHY AND REFERENCES

1 RURAL UTILITIES SERVICE DOCUMENTS

1724D-101A “Electric System Long-Range Planning Guide,” 5/10/1995

1724D-101B “System Planning Guide: Construction Work Plans,” 10/31/2000

1724D-103 “System Planning Guide: System Mapping,” 4/12/2011

1724D-104 “Engineering Economics Computer Workbook Procedure,” 2/3/1998

1724D-105 “Rural Distribution System Conversion Considerations,” 5/22/2009

1724E-202 “An Overview of Transmission Line Studies,” 2/10/1993

1724E-203 “Guide for Upgrading Transmission Lines,” 12/28/1994

1724E-300 “Design Guide for Rural Substations,” 6/7/2001

1730-1 “Electric System Operation and Maintenance,” 4/12/2011

1730A-119 “Interruption Reporting and Services Continuity Objectives for Electric 

Distribution System,” 3/24/2009

7CFR1726 “Electric System Operations and Maintenance”

7CFR1730 “Electric System Operations and Maintenance”

RUS Bulletin 60-2 “Electric System Capacity,” 9/1953 (Expired)

RUS Bulletin 45-4 “Distribution System Energy Losses,” 4/28/1975 (Expired)

RUS Bulletin 60-7 “Service Reliability” (Expired)

RUS Bulletin 60-8 “System Planning Guide, Electrical Distribution Systems,”

10/1980 (Expired)

RUS Bulletin 60-9 “Economical Design of Primary Lines for Rural Distribution 

Systems,” 5/1960 (Expired)

RUS Bulletin 160-1 “Engineering Operations Manual for Rural Electric Systems,”

1/1968 (Expired)
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RUS Bulletin 161-1 “Interrupting Reporting and Service Continuity for Electric 

Distribution Systems,” 3/1972 (Expired)

RUS Bulletin 161-5 “Electric System Review and Evaluation,” 10/1978 (Expired)

2 REFERENCES

CRN Report 00-31 “Guide to When to Replace Distribution Line Conductors,” 2000

CRN Report 06-141 “Optimal Management of Aging Substation Assets: Life Cycle 

Costs and Repair/Replace Strategies,” 4/15/2009

CRN Report 07-02 “Data Structures for Aging Infrastructures,” 11/11/2008

CRN Report 08-09 “Reducing System Losses,” 9/1/2007

CRN Report 98-11 “Motor Problem Resolution and Avoidance,” 1998

“Distribution Systems,” Westinghouse Electric Corporation, 1959, 1965

“Electrical Transmission and Distribution Book,” Central Station Engineers of 

Westinghouse Electric Corporation, 9/1950 (now distributed by ABB Power Systems, 

Inc.)

“Elements of Power System Analysis,” William D. Stevenson, McGraw-Hill Book Co.

“Economic Conductor Analysis: A Microcomputer Application,” John W. Soper, 

Southern Engineering Co., IEEE Paper 85CH2126-1-B1, 1985

“Engineering Economy,” Thuesen, Fabruycky, and Thuesen, Latest Edition, PrenticeHall, Inc.

“Handbook of Engineering Economy,” Max Kurtz, 1984 or Latest Edition, McGraw-Hill, 

Inc.

“Engineering Economy,” Sullivan, Wicks, and Luxhoj, 2003 or Latest Edition, PrenticeHall, Inc.

“Electric Distribution Manual,” R. A. Dewberry, Raytheon Engineers and Constructors, 

Ebasco Division, Electric Power Systems, 1985, Electric World/McGraw-Hill 

Publications Company

“Overhead Conductor Manual,” Southwire Company, Carrollton, Georgia, 1994