· pdf fileinstalled q1000 meter at pagat substation for p-321; verified pts/cts for pending...

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APPENDIX A

Progress Reporting for Dec 09 – May 2010

KEY MANAGEMENT

OBJECTIVE TASK DESCRIPTION STATUS

1 Accurate metering and billing of the U.S. Navy

1.1 Process Ongoing

Navy account set in Utiligy for electronic

meters (Q220 and Q1000) at all Navy

metering points.

Actual billing of Navy is reviewed by GPA prior to issuing to Navy.

Manual billing issued until Utiligy set-up is finalized. Consumption, reads and

billings from March 2007 through December 2009 have been entered in Utiligy.

Starting October 31st, GPA has started using handheld devices to read the Navy

quantum meters for upload to Utiligy.

1.2 Pending

Exploring the feasibility of aggregate

reading No changes during the period of Dec 2009 through May 2010

Currently unavailable; working with software developer; will not be available until

the next release.

Harmon Substation & Tanguisson Substation WAN link ordered to provide

capability of remote Navy Metering

2 Accurate metering and billing of civilian loads

2.1 Process Ongoing

Meter Task Force (MTFC) continues to

oversee, assess, and issue recommendations

for QA/QC of metering and billing

accuracy

System Losses Report Data

Dec 2009 – May 2010

o Three-Phase meter accounts (MTF)

Accounts investigated with meter discrepancies found and

corrected: 4

Accounts investigated with no meter discrepancy: 116

*No Three-Phase meter accounts (MTF) data reported for the months of Feb & April 2010

o Ongoing Single & Three phase meter field investigations (MFI)

Accounts with meter discrepancies found and corrected: 419

Accounts with no meter discrepancy: 3,048

2.2

Process Ongoing

Customer service continuing to resolve

issues for hard to read or inaccessible

meters

Hard to read or inaccessible meters (unsafe conditions, gate lock, vicious dog, etc.)

Dec 2009: 264 accounts

Jan 2010: 196 accounts

Feb 2010: 199 accounts

Mar 2010: 217 accounts

April 2010: 206 accounts

May 2010: 252 accounts

GPA coordinating with Customers for actual readings on a monthly basis after

billings estimated three times their average consumption. Adjustments are made

based on actual/verified readings and consumptions.

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Process Ongoing

Customer service continuing to resolve

issues for hard to read or inaccessible

meters

GPA now notifies customers through system generated letters. 1st Notice given

informs the customer to coordinate for a verified reading or apply for relocation of

meter within 10 days. Final notice given to inform the customer that service can be

terminated.

First and final notices mailed out to customers with inaccessible meters:

o Dec 09: 8 accounts

o Jan 10: 48 accounts

o Feb 10: 75 accounts

o Mar 10: 158 accounts

o Apr 10: 43 accounts

o May 10: 41 accounts

Tracking of letters sent and acknowledgement of customers’ response will be done

via cat codes in the service connection window of Utiligy.

2.3

Process Ongoing

Identify all zero consumption billings and

perform required field investigations

For Dec 2009 thru May 2010, 653 accounts identified with zero consumption and

94 accounts have been investigated and processed for corrective action they include:

o 73 accounts revealed vacant units (no load/minimal consumption)

o 3 accounts have field testing/pending investigation

o 17 accounts have meter change-outs; pending backbilling

o 1 account have pending work clearances/meter removed

A report is created to identify age of the meters servicing these addresses for

possible testing whether they are defective, etc. and also to monitor previous

consumption history.

3 Systematic analysis of billing accounts for possible outliers

3.1 Process Ongoing

Documentation for systematic billing

analysis Continuous

o Descriptive statistics are performed to identify customer accounts for

further investigations.

o Analysis/refinements addressed on a monthly basis as problems are

encountered.

o Both the reading exception and billing exception reports are being

reviewed and scrutinized for each billing cycle monthly. These reports

indicate all the possible reading and billing exception that warrants review

and attention.

3.2 Process Ongoing

Monitoring of reading exception reports in

Utiligy system Continuous - reading exception reports are verified for accuracy and statistics of

reading exception errors are tracked by Accounting. Any item requiring service

order or investigations are being routinely communicated to Customer Service.

3.3 Process Ongoing Additional reports generated monthly in

Utiligy system to assist in billing analysis Continuous – reports are generated monthly to assist in billing analysis

4 Accurate Monitoring, Measurement and Reporting of System Losses

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4.1 Process Ongoing

Civilian load recovery reported by the

MTFC monthly on a system losses report

Dec 2009

o Single & Three phase Meter Field Investigations

11 accounts w/adjustments for backbilling

Revenue recovery: $7,134.38

kWh recovery: 34,211

Jan 2010

o Single & Three phase Meter Field Investigations

12 accounts w/adjustment for backbilling

Revenue recovery: $1,221.73

kWh recovery: 5994

*Pending revenue/kWh recovery reported for the Months of Feb-May 2010

4.2

Identify present metering discrepancies December 2009:

Meter Discrepancies: 97

Meter investigation MFI: 348

Meter investigation INV: 23

Meter change outs: 61

January 2010:





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KEY MANAGEMENT


Process Ongoing February 2010:


Meter investigations MFI: 180

Meter investigation INV:82


March 2010:

Meter Discrepancies:123




April 2010:





May 2010:





Performed load analysis and on site testing of meters.

Ongoing BPL prepaid meter project to install meters. Coordinated with

Engineering and contractors installed 15 each meter with data concentrators for pilot

project. Tested new echelon meters for installation.

A total of 80 meter numbers were updated in Utiligy for accountability.

Ongoing preventive maintenance three phase large consumers.

4.3 Process Ongoing

Procure equipment & systems No equipment & systems procured from Dec 09 – May 2010

4.4

Process Ongoing

Replace, install, and upgrade substation

metering reporting systems December 2009:

Installed Q1000 meter at Pagat Substation for P-321; verified PTs/CTs for

pending energization of feeder.

February 2010:

Refurbished Mobile Sub metering and hardware coordinated with Substation

crew. Location: Dededo Sub and Tumon Substation.14MVA 30MVA.

Ongoing Substation dial up attempt via phone line communication with

Substation Q1000 and Sel-734 metering. Harmon Substation and Pagat

Substation.

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5 Identification of unlisted electric energy consumers

5.1

Process Ongoing

Process in place to identify and minimize

occurrences in Unlisted consuming meters.

Various reports are generated to identify

unlisted energy consumers (i.e., exception,

UNLISTEDMTR report for meter readings

that were not captured in Utiligy and

therefore ran after each upload).

Dec 2009

RPS conducted 3 inspections on meter listed in the consuming listed meter report.

Of that, 1 meter was found with termination seals (not consuming), 1 meter was in

use and removed for no active account, and 1 meter had an account but was not

billed. Information was forwarded to Customer Service for billing.

Jan - Mar 2010

RPS conducted 5 inspections on meters listed in the consuming unlisted report.

Investigations revealed that 1 meter is a sub meter (privately owned); 2 meters

have active accounts and are being billed; 1 meter was in use without an account

and the meter was removed; 1 meter has an active account but was not billed.

Customer Service was provided the meter information to initiate billing.

RPS investigated 30 random meters listed in the billed accounts with minimum

billing report. Of that, 18 locations were confirmed as vacant, 7 were not in use, 1

meter had terminated sealing devices still intact, and 4 were in use by new tenants.

The terminated meter information was forwarded to Customer Service for proper

termination.

April – May 2010

RPS conducted 8 inspections on meter listed in the consuming unlisted report.

Investigations revealed that 1 meter is a sub meter (privately owned), 1 had

termination seals, 1 was registering but did not have an account (RPS removed

meter), 2 had active accounts but were not billed, 2 meters were changed out but

not processed, and 1 was not consuming (reading error). Information on the

terminated meter, change outs and the active accounts not billed were forwarded

to Customer Service for appropriate action.

RPS also investigated 23 meters listed in the billed accounts with minimum billing

report. Of that number, 19 units/houses were vacant, 2 (temp) services were not in

use, and 2 meters were registering with new occupants/tenants.

5.2

Process Ongoing

Tampering and illegal connections

investigated and documented through

GPA Revenue Protection Section, Internal

Audit Section.

Dec 2009

RPS conducted 10 meter tampering/theft of service field investigations. Of that,

6 were confirmed violations they include: 1 meter was found with disconnect seal,

power in use, 1 was swapped (both meters retrieved), 1 meter was inverted

(upside down), and 3 direct hook-ups were found on the service

wire. All 6 cases were reported to the proper authorities and services were

isolated/terminated.

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Process Ongoing

RPS also conducted 19 meter checks: 13 meters were found with seal cuts/corroded,

new white seals and/or lock straps were installed; 1 defective meter was changed

out and information forwarded to Customer Service for back billing; 1 meter

found terminated and not in use, removed and returned to Meter Shop for evaluation;

4 meter systems were inspected but no discrepancies were found.

Jan – Mar 2010

RPS conducted 21 reported/suspected meter tampering investigations. Of that, 12

were cited for confirmed meter tampering/theft of service based on the following

discoveries: 1 inverted (upside down) meter, 6 disconnection/termination seals cut/

removed – power on, 2 unauthorized meter removals, 1 stolen meter, 1 direct hook

up to service line, and 1 reported stolen conductors (approx. 250ft). The remaining

9 were determined not to be tampered: 2 damaged meters reported and was not

compromised, 1 alleged meter swapping (assigned meter registering with sealing

devices still intact), 1 meter seen with disconnection (green) seal, 1 possible

unauthorized removal, 1 meter reported missing, and 3 reported possible tampering

yielding no discrepancies upon investigation.

April - May 2009

RPS conducted 14 reported/suspected tampering investigations. Of that, 8 were cited

as confirmed violations based on the following discoveries: 3 vandalized meters,

1 jumpered meter socket, 1 terminated meter registering found with potential link

opened, 2 disconnected/terminated seals removed (power on) and 1 meter with

damaged strap and disconnection seal remaining, 6 were determined not to be

tampered: 1 inverted (upside down) meter was without load side wirings – removed

and socket secured, 2 meters found on the ground (fell out of meter socket – one

changed out, the other is terminated), 1 reported meter missing was later determined

to be an Emergency Work Clearance, 1 possible direct hook-up was determined to

be on the load side in panel box, and 1 possible meter tampering was found with

a shorted meter box, given Emergency Work Clearance.

RPS also conducted 5 meter checks: 1 meter with a corroded seal (changed), 2

meters changed out (defective), 2 revisits to previously tampered/changed out sites

(no discrepancies found).

6 Power system design and procurement guides considering optimization of system costs and losses

6.1 Process Ongoing

Prepare conductor economics selection

and evaluation guidelines Conductor sizing guidelines based on voltage drop prepared for single-phase loads is

completed. Three-phase guidelines are being finalized. Analysis of existing system

will be conducted through the Medium Range Plan completed in April 2010.

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KEY MANAGEMENT


6.2 Process Ongoing

Stock appropriate transformers Engineering will identify oversized transformers to be changed out. Analysis will

commence after metering data is mapped and modeled to determine actual

consumption from CIS data. 25,000 of 46,000 meters have been updated and mapped.

7 Metering assessment and correction of customer power factor

7.1 Process Ongoing

Evaluating large demand customers to

define magnitude of power factor problem. AMX software is still resolving issues on 5 individual accounts out of 176 accounts in

cycle 23 as of 6/4/2010. GPA has not received instructions to apply the changes from

DV to the PD environment.

AMX software developer has completed the power factor program based on the

KVAH reads.

7.2 Process Ongoing

Evaluating economics of power factor

improvement Evaluation of economics of power factor improvement completed. Engineering will

order capacitors as part of the Distribution capital improvement project program in

accordance with the Medium Range Plan completed in April 2010.

7.3 52% Completed

File new rate – cost of service study

Developed sample design for the load study.

Coordinate with Guam PUC consultants on objectives and design.

Reviewing meter types and meter software; obtain quotes on standard and telecom-

enabled meters for study.

Addressing questions from Bruce Oliver.

T & D reviewing form factor information.

Load Study Meters Delivered

Preparing Maps to Sample locations

Coordinated with GPA Meter Shop for Meter Installation Procedures

Creating Process QMP

Finalizing Sample Data

Removing Disconnected Accounts

Removing Accounts with Inaccessible or Difficult to Read

Troubleshoot and Installed 198 Load Study Meters

Downloaded data for 198 Load Study Meters for October, November and Dec. 2009.

Downloaded data for 198 Load Study Meters for Jan, Feb, Mar & April 2010.

8 Cost effective reactive power compensation

8.1 94 % Completed

Perform long range transmission planning

study

Developed transmission study report template draft.

Provided on-site power flow analysis software training.

Developed preliminary transmission planning criteria.

Finalized load forecast to include civilian and military projects.

Consultant reviewing power flow models.

Finalized power flow models for analysis.

Revising and updating load forecasts

Including wind and non-firm power impacts into study.

Completed revision of load models to account for new JGPO input and updated load

forecasts.

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KEY MANAGEMENT


Completed validation of Spatial forecast including new information on Military loads.

Updated PSLF Power Flow model based on new spatial forecast.

Re-run power flows for 2010 through 2020 and updated figures.

Worked with RW Beck consultant to analyze power flows for 2010 through 2020.

Completed draft of Transmission Study document.

8.2 Completed Connectivity model of distribution circuit

and building load model. GPA Engineering has completed modeling and analysis of the distribution system.

8.3 Completed Perform medium range distribution

planning study. Medium Range Plan completed in April 2010. See attached report

8.4 Progress Ongoing

Procure and install distribution capacitors

Engineering will order capacitors as part of the Distribution capital improvement

Project program in accordance with the Medium Range Plan completed in April

2010.

9 Quality Systems Design & Implementation

9.1 Documentation including supporting

documents is regularly updated & maintained Documents updated and submitted quarterly.

Prepared by: 1)istrihuiion Engineering

DISTRIBUTION ANALYSIS2010-2015

SubmittedApril 26, 2010

RO, BOX 2977 HAGATNA, GUAM u.S.A. 96932-2977 Tel. No: 648-3011 Fax No: 648-3167

Guam Power Authority Distribution Analysis 2010 — 2015

AcknowledgementsThe Guam Power Authority Distribution Analysis Report was a cooperative effort of the EngineeringDivision. This project was led by the Distribution Engineering group to study, manage, and improve thedistribution primary system. Immediate and potential needs were examined and solutions were renderedto meet those needs. The previous distribution report was completed in 1992. Since the 1992 report,resources have been diverted from this work and much has been lost in system asset maintenance,modeling and analysis experience, and process enforcement. For this reason, the generation of this 2010report involved a painstaking process to capture existing system as-builts and characteristics, map andmodel accurate data, analyze current system peifonnance, and consider improvement scenarios tomaximize peiformance and plan for future growth. Therefore, the Distribution Engineering groupgratefully acknowledges the contributions of engineers and technicians and the support of theirsupervisors and managers that have made this report possible.

Project Lead:

ward A. K. Cruz, Engineer II Loti. amacho, Engineer I

Data collection, Mapping and Field verification:

Ariel D. Mata, Engineer I (Distribution Engineering)

Ryan 3. S. Topasna, Engineering Technician II (Distribution Engineering)

Timothy C.S. Muna, Engineering Technician II (Distribution Engineering)

Luke M. Ogo, Engineering Technician II (Distribution Engineering)

Arthur M. Manglona, Construction Inspector Ill (Distribution Engineering)

David A. Delgado, Construction Inspector III (Distribution Engineering)

Noel C. Gulac, Engineering Technician II (Substation/Transmission Engineering)

August Guerrero, Chief Dispatcher PSCC

T&D Meter Relay Division

System Modeling and Analytical Engineering Analysis:

Irwin B. Loyola, P.E., Special Projects Engineer (Substation/Transmission Engineering)

Nanette T. Guerrero, Engineer III (Customer Service Engineering)

Edward A. K. Cruz, Engineer II (Distribution Engineering)

Louis C. Camacho, Engineer I (Distribution Engineering)

Supervisor

‘Melmda R. Camacho, P.E., Manager of Engineermg

—1—


TABLE OF CONTENTS

1.0 EXECUTWE SUMMARY 5

1.1 Objective 5

1.2 Purpose 5

1.3 Scope 5

1.4 Major Findings 5

1.5 Report Organization 6

2.0 DISTRIBUTION PLANNING CRITERIA 7

2.1 Voltage 7

2.2 Loading 7

2.3 Unbalance 7

3.0 DATA ACQUISITION & MODELING 8

3.1 Methods ofData Acquisition 8

3.1.1 QuantumMeter 83.1.2 EnergyLogger 8

3.2 Data 8

3.3 Modeling 8

3.3.1 Historical Modeling 83.3.2 SynerGEE 93.3.3 Load Allocation Method Verification 9

3.4 Demand Factor 10

3.5 Load Factor 12

3.6 Loss Factor 13

3.7 Annual kWh Losses 15

4.0 CAPITAL IMPROVEMENT PROJECTS 16

4.1 Cost Benefits 16

4.2 Load Transfers 16

4.2.1 Permanent to Address Overloads 164.2.2 Temporary to Address Back-Feeding 17

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4.3 Balance Improvement 18

4.4 Capacitor Placement 19

4.5 Balance Improvement & Capacitor Placement 19

4.6 Re-conductoring 19

4.7 Balance Improvement & Re-conductoring 20

4.8 Balance Improvement, Re-conductoring, & Capacitor Placement 20

4.9 Project Priorities 20

5.0 LOAD FORECASTING 22

6.0 5-YEAR PLANNED DISTRIBUTION CIP LIST 24

7.0 SYSTEM SUMMARY AND CONCLUSION 25

7.1 Agana Substation 26

7.2 Andersen Substation 28

7.3 Anigua Substation 29

7.4 Apra Substation 31

7.5 Barrigada Substation 33

7.6 Dededo Substation 35

7.7 GAA Substation 37

7.8 Harmon Substation 38

7.9 Macheche Substation 39

7.10 Pagat Substation 41

7.11 Piti Substation 42

7.12 Pulantat Substation 43

7.13 San Vitores Substation 45

7.14 Talofofo Substation 47

7.15 Tamuning Substation 49

7.16 Tumon Substation 52

7.17 Umatac Substation 55

7.18 Yigo Substation 56

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TABLE OF APPENDICES

APPENDIX A — Loss Factor Empirical Formula Calculation 58

APPENDIX B — Feeder Loss and Load Factors 60

APPENDIX C — Metered data for SynerGEE Simulations 62

APPENDIX D — Initial Load Flow Analysis 64

APPENDIX E — Load Transfer 66

APPENDIX F — Balance Improvement 67

APPENDIX G — Capacitor Placement 69

APPENDIX H — Balance Improvement and Capacitor Placement 71

APPENDIX I — Re-conductoring 73

APPENDIX J — Balance Improvement & Re-conductoring 75

APPENDIX K — Balance Improvement, Re-conductoring, & Capacitor Placement 77

APPENDIX L — Improvements 79

APPENDIX M - T&D Costs 81

APPENDIX N — Backfeeding 82

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1.0 EXECUTIVE SUMMARY

1.1 Objective

This study of the Guam Power Authority’s (GPA) island-wide distribution system was conducted

to evaluate the capability and performance of the primary distribution system from the present

time through fiscal year 2015. Analysis of the system’s existing condition provided the base case

to compare with the American National Standards Institute (ANSI) C84. 1-2006 for voltage

delivery and with the Distribution Planning Criteria 330.1 rev.0 for 75% loading of lines and

transformers, and unity power factor. Corrections to the system were developed to meet these

criteria.

1.2 Purpose

The study’s two fold purpose is to evaluate the existing condition of GPA’s distribution system

and recommend changes that enable the system to meet the Distribution Planning Criteria and

ANSI C84.1-2006 for voltage delivery. The intent is to present an accurate, detailed picture of

the system’s performance and capability. Shortcomings of the system are identified, and then

preferred and alternate solutions are prescribed to meet current and future needs. Justification for

each preferred solution over alternatives is given.

1.3 Scope

The scope of this report covers voltage, loading, and unbalance on the 13.8 kV distribution

system. The time span covers FY 2010 through FY 2015. Improvements to the system are

addressed along with construction costs and kWh loss savings estimates.

1.4 Major Findings

Major results of the study include the following. P-087, P-33 1, P-242, and P-250 are over 75%

loaded. P-087 is loaded at 82% of the normal conductor rating. P-33 1 is loaded at 83% of the

normal conductor rating. P-242 is loaded at 77% of the normal conductor rating. P-250 is loaded

at 81% of the normal conductor rating.

P-087, P-330, P-250, and P-323 have voltages lower than 0.95 pu. P-087 has a minimum voltage

of 0.92 pu. P-330 has a minimum voltage of 0.95 pu. P-250 has a minimum voltage of 0.95 Pu.

P-323 has a minimum voltage of 0.95 pu. P-087 has a voltage unbalance of 3.36% which is

greater than the 3% requirement according to ANSI C84. 1-2006.

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Loading issues are addressed and recommendations are listed in Section 4.2.1. Appendix L

provides a list of feeders with voltage and/or loading violations and the recommended

improvements to meet the Distribution Planning Criteria and ANSI C84. 1-2006.

1.5 Report Organization

The report contains sections in the following order: Distribution Planning Criteria, Data

Acquisition & Modeling, Capital Improvement Projects (CIPs), Load Forecasting, 5 Year

Planned Distribution CIP List, and System Summary and Conclusions.

The section on Distribution Planning Criteria provides the basis for the analysis of the distribution

system. The criterion sets the limits for system corrections. The Data Acquisition & Modeling

section outlines the previous and current methods used to collect, analyze, and normalize data.

All the calculations for Load, Loss, and Demand factor are listed. In the Capital Improvement

Projects section, load transfers were assessed, and benefit cost analyses were conducted for

balance improvement, capacitor placement, re-conductoring, and combinations of the three. The

Load Forecasting section explains the methods used to determine the impact of known future

loads to the system. The 5-Year Planned Distribution CIP List provides a prioritized listing of

planned capital improvement projects. The System Summary and Conclusions section reports on

existing conditions and recommendations itemized by substation for all distribution feeders.

Finally, future planning and analysis goals are discussed.

The loss factor validation spreadsheet is found in Appendix A. Loss and load factors for all the

feeders are listed in Appendix B. Appendix C lists the substation feeder peak metered data used

to run the SynerGEE simulations. Initial feeder load flow results referenced in support of

recommended CIPs are found in Appendix D. Appendices E, F, G, H, I, J, and K provide tables

for loss reduction, cost, and savings from recommended load transfers, re-phasing, capacitor

additions, re-conductoring, as well as combinations of said recommendations. Appendix L

provides a before and after comparison of the electrical characteristics of each feeder after

modeling the recommended CIPs. Construction costs estimated for the different CIPs are listed

in Appendix M. Back-feeding capabilities are listed in Appendix N.

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2.0 DISTRIBUTION PLANNING CRITERIA

Feeder voltage, loading, and unbalance were analyzed against the Distribution Planning Criteria

and ANSI C84. 1-2006 to determine system improvements necessary to meet required standards

of performance.

2.1 Voltage

The first factor addresses the adequacy of GPA’s voltage delivery to customers. The criterion

used is based on ANSI C84. 1-2006 which requires the voltage level at the point of customer

connection to be within ±5% of nominal voltage (0.95 Pu and 1.05 pu). Furthermore, the primary

distribution line voltages shall be within +5% and -2.5% of nominal voltage (1.05 Pu and 0.975

pu). Per-unit or pu represents the normalized value of the physical voltage calculated as the ratio

of the actual voltage to a chosen base. The base used for this study is 13.8 kV. Therefore, the

limits of 0.975 Pu and 1.05 Pu correspond to the physical voltage values of 13.46 kV and 14.49

kV respectively.

2.2 Loading

The second factor addresses the loading limits of the feeder lines and substation transformers.

These limits are set at 75% of the maximum rating of the line as specified in the GPA

Distribution Planning Criteria.

2.3 Unbalance

The third factor addresses imbalances on feeders. ANSI C84. 1-2006 requires electric supply

systems to be designed and operated with a maximum voltage unbalance of 3%.

Voltage unbalance on the system has a serious affect on the quality of power delivery to 3-phase

customers. Voltage unbalances will cause heat generation in 3-phase motors reducing efficiency,

degrading insulation, and leading to equipment failure. Current and load imbalances are reviewed

in terms of how these imbalances impact voltage unbalance.

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3.0 DATA ACQUISITION & MODELING

3.1 Methods ofData Acquisition

Data for distribution feeder modeling was obtained from Quantum meters and energy loggers

installed at the low voltage side (13.8kv) of the substation transformers. 31 feeders had

information obtained from Quantum meters and 32 feeders had information from energy loggers.

3.1.1 Quantum Meter

Data from 2007 to 2009 were obtained from 31 Quantum meters. For the first time in distribution

analysis, real power, reactive power, apparent power, voltage and current values are available at

15 minute intervals. This has had a significant impact on the quality of analysis results and a

considerable improvement over previous GPA distribution studies. Quantum meter data is

representative of feeder behavior and was used to obtain load factor and loss factor.

3.1.2 Energy Logger

Data collected from energy loggers for 32 feeders include voltage, amperage, real power, reactive

power, apparent power, and power factor. Energy logger data was limited to 2 weeks of data at

15 minute intervals. The use of the energy loggers is similar to previous data collection processes

and therefore presents the same limitations. However, the determination of load and loss factors

provides the means to use this data in support of distribution analysis.

3.2 Data

The maximum loading of each feeder was obtained from the metered data. Once the date and

time of maximum loading were determined, the loading was validated and outliers attributed to

back feeding and faults were eliminated. The resulting maximum load day of a feeder was the

24-hour data range used for the analysis of this report. To determine the losses over a one year

period, a loss factor was derived using an empirical formula developed from the Quantum data.

3.3 Modeling

3.3.1 Historical Modeling

DPAS was the distribution modeling software utilized by GPA prior to this study. DPAS

modeling was based on a two week loading interval directly measured using the Dranetz Energy

Recorder. In addition, load was allocated to transformer loads using actual but non-coincident

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kWh values. Peak loading of a feeder was limited to the peak of the selected interval and time of

year was arbitrarily chosen.

3.3.2 SynerGEE

SynerGEE was the modeling software utilized for this report. Loading limits were calculated

from metered data taken at the substation transfonners and distribution feeders. These limits

were based on the maximum ampacity rating of the conductors at the substation. Voltage

regulation and unbalances were determined from system modeling using SynerGEE software.

Line type, line length, breakers, fuses, switches, capacitor banks, and connected KVA of the

13.8kV system were modeled geographically. The program allocated loads throughout the

system with respect to the per-phase metered data at the substation. This metered data is shown

in Appendix C. Load flow analyses were conducted from which data regarding voltage, loading,

and unbalances were obtained to establish the system base case.

Feeder loss improvements were considered to support economic analysis of capital improvement

projects. The losses were calculated from kW losses provided by SynerGEE. Losses were used

to analyze the cost effectiveness of CIP recommendations.

3.3.3 Load Allocation Method Verification

For verification of model results, three feeders were selected to compare kWh allocation to kVA

allocation. kVA allocation uses the connected kVA of the transformers and the feeder loading to

allocate load throughout the system. kWh allocation is a more precise method of allocation that

uses the kWh connected values at each transformer and allocates loads with respect to their

contributions and the feeder peak loading at the substation.

P-244 kWh vs. kVA allocation

Actual metered data collected for every meter serviced by P-244 for the month of November

2009 was compared to the metered max loading taken on November 13, 2009. Non metered

loads were also considered. The maximum difference between the two allocation methods for

phase voltage was 3% with the maximum current difference of 7 amps.

P-332 and P-400 kWh vs. kVA allocation

Average kWh per residential customer taken from the GPA Accrued revenue FY 2009 report is

32.6 kWh per day. Allocation was performed by using this average kWh per day along with the

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Guam Power Authority Distribution Analysis 2010—2015

number of customers per transformer and the connected street light kWh to determine loading for

single phase residential customers. For 3-phase and commercial customers, actual billing

consumption was taken to determine loading. The by-phase results for P-332 showed a

maximum voltage difference of 5% and a maximum current difference of 7 amps. P-400 showed

a maximum voltage difference of 1% and a maximum current difference of 6 amps.

Based on this analysis, kVA allocation is sufficient for primary system modeling to address the

goals of this report. The differences between the various methods of allocation were not

considerable enough to affect the overall behavior of the feeders. kWh allocation will be

addressed in future reports after ongoing projects are completed and a more efficient method of

data collection and monitoring is in place.

3.4 Demand Factor

The equation for demand factor is defined as

DF= maximum demand

total connected demand

Table 1 provides demand factors for the feeders with Quantum data. Table 2 provides the

demand factors for the feeders with Energy Logger data.

-10-

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3.6 Loss Factor

Loss factors are required to determine average losses in kWh over a one year period. The

feeder loss factors were derived from an empirical formula. The general form of the Loss

Factor FLS is

average lossFLS —

peak loss

From Buller and Woodrow [Buller, F. H., and C. A. Woodrow: Load Factor-Equivalent Hour

Values Compared, Electr. World, vol. 92, no. 2, July 14, 1928, pp. 59-60] two formulas are

listed to estimate the loss factor for Urban and Rural areas.

FLS (URBAN) = O.3FLD + 0.7FD

FLS (RURAL) = O.1SFLD +0.85FD

An analysis was conducted to determine the appropriate equation for loss factor where

A+B=l.

FLS = AFLD + BFD

Loss factors obtained through simulations of Quantum data over a 24-hour period were

compared against loss factors calculated through the empirical formula to determine the

appropriate values of A and B. As shown in Figure 1, simulations over a 24-hour period

provided loss factor values.

- 13 -


3000

2500

2000

1500

0-J

1000

D

TIME

Figure 1 — Typical Load Curve

Appendix A provides loss factor data determined from the Quantum simulations as well as

values derived from the empirical formula FLS = AFLD + BFD. FED values were obtained from

the Quantum data and A and B values were selected at 0.05 intervals.

Appendix A also provides the percent differences between the loss factor values from the

simulations and the loss factor calculated from the empirical formulas. Based on the analysis of

this data the values of A and B were determined. The GPA empirical formula for Loss Factor

is

FES =0.15FLD +0.85FD

Appendix B lists the loss factors calculated from this formula.

p’4ILF.O

- 14 -


3.7 Annual kWh Losses

Annual kWh losses are needed to quantify benefits of recommended CIPs. Annual kWh losses

are calculated as follows:

If

average lossFLS —

max loss

and

FLS =0.15FLD +O.85F

Then

average loss = max loss x F

average loss max loss x (0.15FLD + O.85FD)

annual kWh losses = average loss x 8760 hr

- 15 -


4.0 CAPITAL IMPROVEMENT PROJECTS

The existing system performance was compared against required standards to recommend

improvement projects. Load transfers, phase balancing, capacitor placement, and re-conductoring

were considered. Combinations of this work were also analyzed. The final capital improvement

plan was developed and prioritized based on immediate operational needs, distribution system

criteria and favorable cost benefit analysis to reduce system losses.

4.1 Cost Benefits

Benefit Cost Analyses were based on an inflation rate of 6.2% (First Hawaiian Bank Economic

Forecast, 2009 Guam — CNMI edition.) Appendices E, F, G, H, I, J, and K list the total kWh

savings per annum and total installation costs for the selected projects using a current energy rate

of $0.098 1/kWh. Appendix M provides installation cost estimates. Improvements can be

justified with a Benefit Cost Ratio greater than 1. The Benefit Cost analysis (BCA) is determined

as follows.

Useftul Life kWh loss savings per annum.Net Present Value of Savings =

(i + Inflation Rate)’

Net Present Value of SavingsBenefit Cost Ratio=

Construction Costs

4.2 Load Transfrrs

4.2.1 Permanent to Address Overloads

P-087, P-33 1, P-242, and P-250 are over 75% loaded. Load transfer, feeder line upgrades, new

feeders and/or substations are options considered to bring these feeders within the GPA loading

standard. Load transfer is the preferred method to address feeder overloads because of minimal

labor and materials required. Load transfers were analyzed between the critical feeders and the

surrounding feeders. Listed in Table 3 are the load transfer values for P-087, P-33 1, and P-250

and the resulting impacts on loading, voltage, unbalance, and losses on these feeders and the

corresponding feeder ties.

-16-


Feeder Analysis - Load Transfer Changes

Source Amp % Max % Volt MinimumLoad (Metered) MAX Loss

Loading % Unbalance Unbalance Voltage (pu)Feeder Substation kVA (kW) (Synergy)

(Synergy) (Synergy) (Synergy)

Before After Before After Before After Before After Before After Before AfterP-087 Dededo 9,465 6,024 82.0% 51.0% 18.0% 19.7% 3.36% 1.40% 0.916 0.970 448.5 159.0P-046 Harmon 1,553 4,987 15.0% 46.0% 8.6% 12.6% 0.12% 1.94% 1.020 0.960 7.2 130.0

P-331 Yigo 8,829 7,039 83.0% 64.0% 17.6% 19.1% 1.00% 0.68% 0.999 1.008 63.8 42.0P-089 Dededo 4,127 5,871 36.0% 50.0% 26.5% 24.6% 0.88% 1.13% 1.010 0.998 30.7 63.0

P-250 Agana 8,655 7,549 81.0% 69.0% 20.8% 17.4% 1.90% 1.40% 0.952 0.966 331.2 243.0P-294 Pulantat 5,107 6,226 48.0% 57.0% 13.6% 17.2% 1.19% 1.63% 0.980 0.952 130.3 207.0

Table 3 — Load Transfer Changes

Feeder modeling and analysis of load transfers on P-087, P-33 1, and P-250 resulted in 3 switches

installed for a total construction cost of $33,197.61 and a loss savings per annum of $96,267.64.

Assuming a useful life of 5 years, the benefit cost ratio for load transfer is 12.15. Construction

costs and loss savings per annum are listed by feeder in Appendix E.

There is no load transfer scenario available for P-242. P-242 is entirely underground and is tied

to P.403 and P-243. However, these feeders located along San Vitores Road in Tumon are

already planned to accommodate current permitted projects. Consequently, no spare capacity will

be available to relieve overloading on P-242.

4.2.2 Temporary to Address Back-Feeding

Load transfers were also assessed for supporting loads from adjacent feeders under emergency

conditions. Under these circumstances, loading was allowed up to the maximum capacity of the

feeders and voltages were allowed up to 0.95 pu and 1.05 pu in accordance ANd C84. 1-2006 for

emergency conditions. Backfeeding scenarios provided in Appendix N were discussed with

PSCC and T&D to validate existing conditions and feasibility.

All dIP changes to feeders were accounted for in the back-feeding table in Appendix N. Load

transfers were assumed as well as balance improvement, capacitor placement, and re

conductoring. Typically, back-feeding scenarios involved one to one transfer between 2 feeders.

The following list involves multi-feeder coordination for temporary backfeeding.

-17-


1. P-089 back-feeding requires partial load transfer from P-33 1 to P-332 prior to

transfer to P-332.

2. P-330 back-feeding requires partial load transfer to P-046 prior to transfer to P

332.

3. P-33 1 back-feeding requires partial load transfer to P-332 prior to transfer to P

089.


111.

5. P-ill back-feeding requires partial load transfer to P-243 prior to transfer to P

271.


243.

7. P-245 back-feeding with P-3 10 and P-244 requires line extensions and switch

installations.

8. P-403 back-feeding requires partial load transfers to P-ill and P-240 prior to

transfer to P-243.

9. P-205 back-feeding requires partial load transfer from P-401 to P-203 prior to

transfer to P-40 1.

10. P-2 10 back-feeding requires load transfers and switch installations for peak back-

feeding.

11. P-250 back-feeding requires load transfers and switch installations for peak back-

feeding.

12. P-323 back-feeding requires load transfers and switch installation for peak back-

feeding.

13. P-290, P-292, and P-298 back-feeding requires underground line extensions and

switch installations in existing conduits and switch pads.

14. P-003 back-feeding requires underground line extensions and switch

installations.

4.3 Balance Improvement

Balance improvements were analyzed for all the feeders. Feeder modeling and analysis resulted

in 98 lateral phase changes for a total construction cost of $10,446.80 and a loss savings per

annum of $34,672.01. Assuming a useful life of 5 years, the benefit cost ratio for balance

- 18 -


improvements is 13.90. The cost per feeder, and number of lateral phase changes per feeder are

listed in Appendix F.

4.4 Capacitor Placement

Capacitors are needed on the system to boost lowest voltage, correct reactive power, and improve

power factor. The useful life of a capacitor bank is 15 years. Installation of 6-450 kVAR

capacitor banks, 6-900 kVAR capacitor banks, and 9-1350 kVAR capacitor banks are

recommended for a total construction cost of $85,408.62 and a kWh loss savings per annum of

$38,348.33. The resulting benefit cost ratio of capacitor placement is 4.30. The cost and number

of capacitor banks per feeder are listed in Appendix G.

4.5 Balance Improvement & Capacitor Placement

Balance improvements and capacitor placements were conducted to correct unbalance, boost

lowest voltage, correct reactive power, and improve power factor. The number of lateral phase

changes recommended in Section 4.3 was applied. Then, capacitor placement was analyzed.

Based on this analysis, 6-45 0 kVAR capacitor banks, 6-900 1CVAR capacitor banks, and 9-1350

kVAR capacitor banks are recommended. The total construction cost is estimated at $95,855.42

with a kWh loss savings per annum of $84,286.20. Assuming a useful life of 15 years, the benefit

cost ratio is 8.43. The cost, number of lateral phase changes, and number of capacitor banks per

feeder are listed in Appendix H.

4.6 Re-conductoring

Re-conductoring work focused on the main line from the substation to the tie switches between

feeders. 336 AAC conductor was modeled for the distribution main lines. An evaluation of 13.8

kV conductor standards is not addressed in this report. Revisions to conductor standards must

consider the effects on current stock of supporting materials and accessories. Loading and back-

feeding capabilities were considered when determining re-conductoring projects. Appendix I lists

the total T&D costs, kWh savings, and total line lengths re-conductored. Assuming a useful life

of 15 years, the BCA for re-conductoring to lower power losses and increase loading capability

gave a Benefit Cost Ratio of 1.48. The total construction cost for the scenario is $558,738.08

with a kWh loss savings per annum of $85,970.93.

-19-


4.7 Balance Improvement & Re-conductoring

The BCA for balance improvements and re-conductoring combines the recommended

improvements of phase changes and line re-conductoring previously discussed. The benefit cost

ratio for balance improvement and re-conductoring is 2.11. The total construction cost for the

scenario is $569,184.88 with a kWh loss savings per annum of $125,286.73. The cost, number of

lateral phase changes, and wire upgrades are listed in Appendix J.

4.8 Balance Improvement, Re-conductoring, & Capacitor Placement

Balance Improvement, re-conductoring, and capacitor placement is a combination of the three

different methods used to improve losses, voltage, and unbalance. The total construction cost for

the scenario is $654,593.50 with a kWh loss savings per annum of $170,461.35. The cost,

number of lateral phase changes, number of capacitor banks, and line upgrades are listed in

Appendix K. Assuming a useful life of 15 years, the benefit cost ratio is 2.07.

4.9 Project Priorities

Capital Improvement projects listed in Table 4 are prioritized by loading (priority 1), minimum

voltage and unbalance (priority 2), and then reliability (priority 3).

- 20 -

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5.0 LOAD FORECASTING

Information on future load is obtained from numerous sources. Substantial information comes

from the Guam Land Use Commission, discussions with engineering firms and developers, and

plan review records which reflect normal system growth and anticipated growth related to the

military buildup. Based on this growth data, 82.38 MVA of loads were allocated throughout the

system as shown in Table 5. The SPORD division also provided growth data in the form of

annual peaks from 2010 to 2015. Total forecasted growth was estimated at 33 MVA as shown in

Table 5.

Engineering Growth SPOR]) Forecast(MVA) (MVA)*

15.10 923.27 825.87 78.07 610.07 382.38 33

*5QJ Forecastprovided via e-mail on 11-04-2009from SPORD to Engineering

Table 5 — Forecast

Based on an analysis of the impacts of this growth, the distribution system will require

improvements to correct deficiencies and meet system performance standards. 9 feeders will

exceed the 75% loading criteria and 2 feeders will violate the voltage requirements by the year

2015. Listed in Table 6 are loading and voltage issues forecasted up to year 2015. Table 7

provides a list of proposed projects by year.

- 22 -

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6.0 5-YEAR PLANNED DISTRIBUTION CIP LIST

The 5-year planned distribution CIP listing shown in Table 8 lists the FY20 11 through FY20 15

schedule. The list includes all CIP’s from sections 4 and 5. Current issues regarding loading,

voltage, and unbalance are addressed first. Then, the list is sub-prioritized by loss reduction.

Finally, forecasted load increases are scheduled according to the estimated required date as

discussed in section 5.0.

GUAM POWER AUTHORITYDistribution Engineering Capital Improvement Projects (CII’) FY 2011 - FY 2015 X $1,000

CIP Project Name Reason FY10 FY11 FY12 FY13 FY14I P-4(J2 load transter to P-24 1 Loading 11 11‘2 P-087 Line Improvements Loading 13 Ii3 P-250 Line Improvements Loading 82 824 P-331 Lme Improvements Loading 18 18S Commission&bxtendP-112 Loading 200 2,500 3,000 300 6,0006 P-088 load transfer to P-272 Loading 1 1 1 11 P-203 load transfer to P-401 Loading 11 118 P-330 Lme Improvements Voltage 3 39 P-323 Line Improvements Voltage 14 1410 P-322 Line Improvements Reliability 1 ‘I

1 1 Pulantat Feeder Line improvements Reliability 112 Apra Feeder Line Improvements Reliability 3 313 P-260 Feeder Line Improvements Reliability 32 3214 Macheche Feeder Line Improvements Reliability 4 415 Harmon Feeder Line Improvements Reliability 62 62lb Dededo Feeder Line Improvements Reliability 3 31/ Tamuning Feeder Line Improvements Reliability ‘22 2218 Tumon Feeder Line improvements Reliability 46 4619 P-203 Feeder Line Improvements Reliability 38 3820 P-262 Feeder Line improvements Reliability 109 10921 P-261 Feeder Line Improvements Reliability 66 6622 Agana Feeder Line Improvements Reliability 35 3523 Barrigada Feeder Line Improvements Reliability 3 324 Anigua Feeder Line Improvements Reliability 54 5425 Umatac Feeder Line improvements Reliability I26 P-400 Feeder Line Improvements Reliability 1 12/ GAA Feeder Line Improvements Reliability28 P-005 Feeder Line Improvements Reliability29 P-206 Feeder Line Improvements Reliability 34 3430 P-272 Line Improvements Reliability 3/ 37

Install, Commission, & Extend New250 500 500 1 250

31 Feeder at Apra Loading32 P-294 Capacitor bank Installation Reliability 733 P-087 Capacitor bank Installation Reliability 7 134 Commission & Extend P-320 Loading 250 500 500 1,25035 Reconstruct & Commission P-27 Loading 1,000 1,000 800 2,800

Table 8—5-Year Distribution CP list

Priority FY15 Total

Totals: 399 2,94Z 3,Jhi b,U04 hUUU 1,3(H) i,ui

- 24-


7.0 SYSTEM SUMMARY AND CONCLUSION

The Guam Power Authority Distribution system has approximately 520.76 MVA of connected

load. 152.87 MVA of the connected load is utilized. Distribution losses are 2.044 MW or about

1.3% of the distributed kW, this translates to 49.04 MWh a day or 17.9 GWh per year.

System analysis has revealed distribution performance is adequate and the recommended

improvements are attainable and provide direct benefits to GPA’s quality of service. Further

analysis will be conducted as secondary information including connectivity and loading is

modeled.

1. Meter ID Project — Completion of this task will provide specific geographic

locations for GPA’s 40,000+ meters complete with Service Addresses for ease of

updating through the GPA CIS/Utiligy System. This project will tie in all meters

to the distribution transformer source which will assist with obtaining accurate

SAIFI and CAIDI indices.

2. kWh Allocation — After completion of Engineering’s Meter II) Project, the

distribution model will be updated with customer load information and load

allocation will be performed via kWh allocation. KWh allocation is a more

precise method of allocation that uses the kWh values connected at each

transformer and allocates loads with respect to their contributions. This will

remove any errors with respect to oversized transformers.

3. Transformer Sizing — After completion of the meter ID Project, transformer sizes

will be analyzed to ensure transformers are not oversized with respect to their

loads.

4. Feeder Metering and Load Profiling — The SEL 734 meter will be installed in all

distribution feeders to gather feeder loading data. Completion of this task will

provide accurate historical feeder data for use with the line models.

5. Data Merge (GIS and SynerGEE Model) — This task involves creating a common

database for GIS and SynerGEE for easy maintenance of data files.

6. Transformer and Secondary Modeling — This task aims to model the transformers

and secondary lines of the distribution system for optimization. Completion of

this task will require an upgrade of the line modeling software.

- 25 -


7.1 Agana Substation

II SUBSTATION: Agana FEEDERS: P-250, P-251, P-252, P-253

Transformer: T-65Capacity: 15/18.7/22.4 MVA OA/FA/FOALoading: 85%

FEEDER P-250

Existing conditionsVoltage Minimum voltage is 0.952 pu with a 1.03 pu distribution

bus voltageLoading The circuit is loaded at 8,655 kW with maximum line

loading at 81% of existing line ratingUnbalance Voltage unbalance is 1.90%Losses 331.2kW

Recommended ChangesLoad transferred from P-250 to P-294 to reduce loading from 81% to 69%.Re-phasing will be completed to balance the loads and capacitors will be

• installed to boost lowest voltage, correct power factor, and decrease line losses.Re-conductoring will be completed to improve losses and increase loadingcapability.

FEEDER P-251

Existing conditionsVoltage

Recommended ChangesCapacitors will be installed to boost lowest voltage, correct power factor, anddecrease line losses.

Minimum voltage is 1.025 pu with a 1.03 pu distributionbus voltage

Loading The circuit is loaded at 3,874 kW with maximum lineloading at 36% of existing line rating

Unbalance Voltage unbalance is 0.04%Losses 8.7kW

- 26 -


FEEDER P-252

Existing conditionsVoltage Minimum voltage is 1.008 Pu with a 1.03 Pu distribution


loading at 41% of existing line ratingUnbalance Voltage unbalance is 0.65%Losses 42.2 kW

Recommended ChangesRe-phasing will be completed to balance the loads and reduce line losses.

FEEDER P-253


Recommended ChangesRe-phasing will be completed to balance the loads and capacitors will beinstalled to boost lowest voltage, correct power factor, and decrease line losses.Re-conductoring will be completed to improve losses and increase loadingcapability.

Minimum voltage is 1.007 pu with a 1.03 Pu distributionbus voltage



- 27 -


7.2 Andersen Substation

II SUBSTATION: Andersen FEEDERS: P-067

Transformer:Capacity: 15/18.7/22.4 MVA OA/FAIFOALoading: 110%

FEEDER P-067



loading at 82% of existing line ratingUnbalance Voltage unbalance is 0.39%Losses 168kW

Recommended ChangesRecommendations pending documentation.

-28-


7.3 Anigua Substation

II SUBSTATION: Anigua FEEDERS: P-280, P-281, P-282, P-283

Transformer: T- 100Capacity: 1 8/24/3 0 MVA OA/FA/FOALoading: 50%

FEEDER P-280

Existing conditionsVoltage Minimum voltage is 1.026 pu with a 1.03 Pu distribution




FEEDER P-28l


Recommended ChangesCapacitors will be installed to boost lowest voltage, correct power factor, anddecrease line losses.Re-conductoring will be completed to improve losses and increase loadingcapability.

Minimum voltage is 1.011 Pu with a 1.03 Pu distributionbus voltage


Unbalance Voltage unbalance is 0.06%Losses 37.0 kW

-29 -


FEEDER P-282

Existing conditionsVoltage Minimum voltage is 1.012 Pu with a 1.03 pu distribution




FEEDER P-283





-30-


7.4 Apra Substation

II SUBSTATION: Apra FEEDERS: P-220, P-221, P-222, P-223

Transformer: T-70Capacity: 10/12.5 MVA OA/FAIFOALoading: 94%

FEEDER P-220


bus voltageLoading The circuit is loaded at 703 kW with maximum line


Recommended ChangesRe-phasing will be completed to balance the loads and capacitors will beinstalled to boost lowest voltage, correct power factor, and decrease line losses.

I FEEDER P-221





-31 -


FEEDER P-222

Existing conditionsVoltage Minimum voltage is 1 .024pu with a 1.03 Pu distribution


loading at 17% of existing line ratingUnbalance Voltage unbalance is 0.0 1%Losses 5.0kW


FEEDER P-223

Existing conditionsVoltage Minimum voltage is 1.0 17 Pu with a 1.03 Pu distribution




- 32 -


7.5 Barrigada Substation

II SUBSTATION: Barrigada FEEDERS: P-210, P-212, P-213


FEEDER P-210




Recommended ChangesNone

FEEDER P-212



loading at 45% of existing line ratingUnbalance Voltage unbalance is 0.8 1%Losses 40.6 kW


- 33 -

Guam Power Authority Distribution Analysis 2010— 2015

FEEDER P-2 13






-34-


7.6 Dededo Substation

II SUBSTATION: Dededo FEEDERS: P-087, P-088, P-089


FEEDER P-087




Recommended ChangesLoad transferred from P-087 to P-046 to reduce loading from 82% to 51%.Re-phasing will be completed to balance the loads and reduce line losses.Re-conductoring will be completed to improve losses and increase loadingcapability.

FEEDER P-088

Minimum voltage is 1.007 pu with a 1.03 Pu distributionbus voltage


Unbalance Voltage unbalance is 0.5 1%Losses 69.1 kW



- 35 -


FEEDER P-089




Recommended ChangesRe-phasing will be completed to balance the loads.

-36-


7.7 GAA Substation

II SUBSTATION: GAA FEEDERS: P-310, P-311, P-312

Transformer: T-105Capacity: 18/24/30 MVA OA/FA!FOALoading: 28%

FEEDER P-310





FEEDER P-311





FEEDER P-3 12






-37-


7.8 Harmon Substation

I[SUBSTATION: Harmon FEEDERS: P-046, P-ill

Transformer: T-2 1Capacity: 7.5/9.375 MVA OA/FA!FOALoading: 34%

FEEDER P-046




Recommended ChangesRe-conductoring will be completed to improve losses and increase loadingcapability.

FEEDER P-ill





- 38 -


7.9 Macheche Substation

II SUBSTATION: Macheche FEEDERS: P-270, P-271, P-272

Transformer: T-90Capacity: 18/24/30 MVA OA/FA/FOALoading: 54%

FEEDER P-270





FEEDER P-271





-39-


FEEDER P-272



Minimum voltage is 1.027 Pu with a 1.03 pu distributionbus voltage



- 40-


7.10 Pagat Substation

II SUBSTATION: Pagat FEEDERS: P-322, P-323

Transformer: T- 115Capacity: 18/24/30 MVA OA/FA/FOALoading: 48%

FEEDER P-322





FEEDER P-323





-41-


7.11 Piti Substation

II SUBSTATION: Piti FEEDERS: P-003, P-005, P-007

Transformer: T-7Capacity: 10.5 MVA OA/FA!FOALoading: 44%

FEEDER P-003





FEEDER P-005




Recommended ChangesRe-phasing will be completed to further balance loads.

FEEDER P-007





-42 -


7.12 Pulantat Substation

II SUBSTATION: Pulantat FEEDERS: P-290, P-292, P-294, P-298, P-301

Transformer: T-95 & T-96Capacity: 18/24/30 MVA & 30 OAJFA/FOA

MVALoading: 33% & 14%

I FEEDER P-290


bus voltageLoading The circuit is loaded at 565 kW with maximum line



j FEEDER P-292


bus voltageLoading The circuit is loaded at 83 kW with maximum line loading

at 1% of existing line ratingUnbalance Voltage unbalance is 0.0%Losses 0.0 kW


-43 -


FEEDER P-294





FEEDER P-298





FEEDER P-301


Recommended ChangesRe-phasing will be completed to further balance the loads.




- 44-


7.13 San Vitores Substation

II SUBSTATION: San Vitores FEEDERS: P-400, P-401, P-402, P-403

Transformer: T-122Capacity: 18/24/30 MVA OA!FAJFOALoading: 71%

FEEDER P-400



loading at 43% of existing line ratingUnbalance Voltage unbalance is 0%Losses 19.5kW


FEEDER P-401





-45 -


FEEDER P-402



loading at 19% of existing line ratingUnbalance Voltage unbalance is 0%Losses 3.0kW


FEEDER P-403





-46 -


7.14 Talofofo Substation

I SUBSTATION: Talofofo FEEDERS: P-260, P-261, P-262

Transformer: T-80Capacity: 10/12.5 MVA OA/FA!FOALoading: 93%

I FEEDER P-260




Recommended ChangesRe-phasing will be completed to balance the loads and capacitors will be installed toboost lowest voltage, correct power factor, and decrease line losses.

. Re-conductoring will be completed to improve losses and increase loading capability.

I FEEDER P-261




Recommended ChangesRe-phasing will be conducted to balance the loads.Re-conductoring will be completed to improve losses and increase loadingcapability.

- 47 -


FEEDER P-262





Re-conductoring will be completed to improve losses and increase loadingcapability.

-48 -


7.15 Tamuning Substation

h SUBSTATION: Tamuning FEEDERS:P-201, P-202, P-203, P-204, P-205,

Transformer: T-50 & T-51Capacity: 15/18.7/22.4 MVA & OA/FA/FOA

15/20/28 MVALoading: 54% & 66%

I FEEDER P-201





FEEDER P-202


None




Recommended Changes

- 49 -


FEEDER P-203





FEEDER P-204





FEEDER P-205





-50-


FEEDER P-206

Existing_conditionsVoltage Minimum voltage is 1.029 Pu with a 1.03 Pu distribution




- 51 -


7.16 Tumon Substation

h SUBSTATION: Tumon FEEDERS:P-242, P-243, P-244, fi

Transformer: T-60 & T-61Capacity: 15/18.7/22.4 MVA & OAIFAJFOA

18/24/30 MVALoading: 63% & 70%

FEEDER P-240




Recommended ChangesCapacitors will be installed to boost lowest voltage, correct power factor anddecrease line losses.Re-conductoring will be completed to improve losses and increase loadingcapability.

FEEDER P-241





- 52 -


FEEDER P-242





FEEDER P-243



loading at 19% of existing line ratingUnbalance Voltage unbalance is 0%Losses 4.0kW V

Recommended ChangesRe-phasing will be completed to balance the loads. Balance Improvement willlower losses to 47.7 kW at a cost of $319.80 for a KWh saving of $196.85/year.

FEEDER P-244





- 53 -


FEEDER P-245





FEEDER P-246





- 54 -


7.17 Umatac Substation

II SUBSTATION: Umatac FEEDERS: P-340, P-341

Transformer: T-120Capacity: 18/24/30 MVA OA/FAJFOALoading: 12%

FEEDER P-340

Existing conditionsVoltage Minimum voltage is 0.99 1 Pu with a 1.03 Pu distribution




FEEDER P-341





-55-


7.18 Yigo Substation

II SUBSTATION: Yigo FEEDERS: P-330, P-331, P-332

Transformer: T-30Capacity: 18/24/30 MVA OA/FA/FOALoading: 69%

FEEDER P-330





FEEDER P-33 1




Recommended ChangesLoad transferred from P-33 1 to P-089 to reduce loading from 83% to 64%.Re-phasing will be completed to balance the loads and capacitors will beinstalled to boost lowest voltage, correct power factor, and decrease line losses.

- 56 -

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APPENDIX A — Loss Factor Empirical Formula Calculation (continued)

A B between Simulatons and Empirical FormulaP-202 P-204 P-243 P-244 P-245 P-246 P-280 P-281 P-310 P-311 P-312

0.05 0.95 1% 3% 1% 4% 0% 2% 9% 6% 2% 2% 8%0.1 0.9 1% 2% 0% 3% 1% 1% 7% 4% 1% 3% 7%015 085 4%- 1% 2% 1% 3°/ 1% S% 2°4 1% 4% 6%0.2 0.8 7% 1% 3% 1% 5% 2% 4% 0% 2% 5% 5%

0.25 0.75 10% 2% 4% 3% 7% 4% 2% 2% 3% 6% 4%0.3 0.7 13% 3% 6% 5% 9% 5% 0% 4% 5% 7% 2%

0.35 0.65 16% 4% 7% 7% 11% 6% 1% 6% 6% 8% 1%0.4 0.6 18% 6% 8% 9% 13% 8% 3% 8% 8% 8% 0%

0.45 0.55 21% 7% 10% 1% 15% 9% 5% 10% 9% 9% 1%0.5 0.5 24% 8% 11% 3% 17% 10% 7% 12?/o 10% 10% 2%

0.55 0.45 27% 9% 12% 5% 18% 12% 8% 15?/o 12% 11% 3%0.6 0.4 30% 1% 14% 17% 20% 13% 10% 17% 13% 12% 4%

0.65 0.35 32% 2% 15% 19% 22% 14% 12% 19% 15% 3% 6%0.7 0.3 35% .1% 16% 21% 24% 16% 13% 21% 16% 14% 7%

0.75 0.25 38% 14% 18% 22% 26% 17% 15% 23% 17% 15% 8%0.8 0.2 41% 16% 19% 24% 28% 19% 17% 25% 19% 16% 9%

0.85 0.15 44% 17% 20% 26% 30% 20% 19% 27% 20% 16% 10%0.9 0.1 46% 18% 22% 28% 32% 21% 20% 29% 21% 17% 11%

A B% Difference between Simulations and Empirical Formula

P-322 P-330 P-331 P-332 P-340 P-341 P.400 P-401 P-402 P-403 AVE.0.05 0.95 1% 4% 4% 71% 6% 49% 23% 23% 3% 5% 4%0.1 0.9 1% 2% 2% 70% 3% 50% 23% 24% 2% 4% 3%O15 ro8 $% 1% 0% 68% 1% 52% 42% 25% 1% 3% 3%0.2 0.8 5% 3% 2% 67% 2% 53% 21% 25% 1% 2% 3%

0.25 0.75 7% 6% 4% 66?/o 4% 54% 21% 26% 0% 1% 4%0.3 0.7 8% 9% 5% 65% 7% 56% 20% 27% 1% 0% 5%

0.35 0.65 10% 11% 7% 64% 9% 57% 19% 27% 2% 1% 6%0.4 0.6 12% 14% 9% 62% 12% 58% 19% 28% 3% 2% 8%

0.45 0.55 14% 16% 11% 61% 14% 60% 18% 28% 4% 4% 9%0.5 0.5 16% 19% 13% 60% 17% 61% 17% 29% 5% 5% 11%

0.55 0.45 18% 21% 15% 59% 19% 62% 16% 30% 6% 6% 13%0.6 0.4 20% 24% 16% 57% 22% 64% 16% 30% 7% 7% 14%

0.65 0.35 22% 27% 18% 56% 24% 65% 15% 31% 8% 8% 16%0.7 0.3 24% 29% 20% 55% 26% 66% 14% 32% 9% 9% 17%

0.75 0.25 26% 32% 22% 54% 29% 68% 14% 32% 9% 10% 19%0.8 0.2 28% 34% 24% 52% 31% 69% 13% 33% 10% 11% 21%

0.85 0.15 30% 37% 25% 51% 34% 70% 12% 34% 11% 12% 22%0.9 0.1 32% 40% 27% 50% 36% 72% 12% 34% 12% 13% 24%

0.95 0.05 34% 42% 29% 49% 39% 73% 11% 35% 13% 14% 25%

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APPENDIX E - Load Transfer

Load Transfer

42.063.0

0.640.56

-$3,554.30 $11,065.87

Total $96,267.64 $33,197.61

* kWh savings per annum = (KW loss d(fJ) XLossFactor X 8760hr X $0. 0981

P-331P-089

Yigo

MAX Loss (kW)kWh Savings

Feeder Substation (Synergy) Loss Factor T&D Costper Annum

Before AfterP-087 Dededo 448.5 159.0 0.64 $93,793.55 $11,065.87P-046 Harmon 7.2 130.0 0.62

P-250 Agana 331.2 243.0 0.61 $6,028.38 $11,065.87P-294 Pulantat 130.3 207.0 0.61

Dededo63.830.7

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APPENDIX M - T&D Costs

Estimates in this appendix are used to generate Transmission and Distribution installation andlabor costs for Appendices E through K.

$11,065.8? (Includes 10% mark up)* Estimates based on GPA cost program.

T&D Cost to Re-tap 1 Lateral* *

* * * * Estimates based on GPA cost program.

T&D Cost to install 1 switch*

Materials none $ -

Labor 2 man crew for lhr @ $16.64 $ 33.28Equipment Bucket Truck $ 65.00Overhead .25(Labor) X . lO(Materials) $ 8.32TOTAL $ 106.60‘ Estimates assumed are based on T&D recommendations.

T&D Cost to install Capacitor Bank***

450 kVAR Capacitor Bank $ 2,247.47900 kVAR Capacitor Bank $ 2,247.471350 kVAR Capacitor Bank $ 6,493.22

Estimates are based on previous CIP work orders.

T&D Cost to Re-conductor 1-180ft Span****

$1874.96 (Includes 10% mark up)

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