Republic of the Philippines
ENERGY REGUlATORY COMMF
San Miguel Avenue, Pasig City
Approved for
Pestng
20
RESOLUTION NO. ___, Series of 2017
ARESOLUTION ADOPTING THE ERC RULESFOR
SETFING THE DISTRIBUTION SYSTEM LOSS CAP AND
ESTABLISHING PERFORMANCE INCENTIVE SCHEME FOR
DISTRIBUTION EFFICIENCY
WHEREAS, Section 43 (0 of Republic Act No. 9136, otherwise
known as the Electric Power Industry Reform Act of 2001 (EPIR.A)
provided that the cap on the recoverable rate of system loss prescribed
in Section 10 of Republic Act No. 7832 is amended and shall be
replaced by caps which shall be determined by the Energy Regulatory
Commission (ERC) based on load density, sales mix, cost of service,
delivery voltage and other technical considerations it may promulgate;
WHEREAS,. on September 2016, the Commission, after public
bidding, engaged the services of a consultant, PowerSolv Inc. to conduct a
study on system loss for purposes of establishing new caps based on the
abovementioned parameters;
wHEREAS,:. sa id engagement required PowerSolv Inc. to: i) come
up with a new disjiijbution system1oss caps (technical and non-technical
losses) including incentive schethëidiflystem loss reduction based on the
criteria provided in the EPIRA; 2) review and enhance, if necessary, the
existing models/methodology for segregating the technical and nontechnical losses; and 3) prepare the draft rules for the determination of
caps for recoverable levels of distribution system losses;
WHEREAS, PowerSolv Inc. was instructed that the methodology
should consider characteristics that include load density, sales mix, cost of
service, delivery voltage and any other technical considerations, as
provided in the EPIRA, necessary for establishing different caps for
different customer classes for different Distribution Utilities (DUs);
20
, Series of 2017
Resolution No.
A Resolution Adopting the ERG Rules for Setting the Distri,ution System 1oss Cap
and Establishing Performance Incentive Scheme for Distribution Efficiency
Page
2
of 3
WHEREAS, Public Consultations on the draft rules were
conducted in Manila on May 29-30, 2017 for the Luzon Stakeholders; in
Cebu City for Visayas Stakeholders on June 01, 2017 and in Manila and
Davao for Mindanao Stakeholders on August 09, 2017, and August 31,
2017, respectively;
WHEREAS, on July 05, 2017 and July 06, 2017 a Focus Group
Discussion (FGD) was conducted at the Distribution Management
Committee (DMC) conference area for Electric Cooperatives and Private
Distribution Utilities, respectively;
WHEREAS, after said public consultations and FGDs, PowerSolv
Inc. submitted its proposed Rules for Setting the Distribution System Loss
Cap and Establishing Performance Incentive Scheme for Distribution
Efficiency (Rules);
'WHEREAS, the proposed Rules was presented to the Senate
Committee on Energy and the Committee on Energy of the House of
Representatives on separate committee hearings;
WHEREAS, the Commission it its 05 December 2017 Regular
Commission Meeting resolve to approve the Rules for Setting the
Distribution System Loss Cap and Establishing Performance Incentive
Scheme for Distribution Efficiency, hereto attached as Annex "A" and made
an integral part of this Resolütion;'"
WHEREAS, the new Rules grouped the Distribution Utilities into
four (4) clusters based on similar technical considerations as discussed in
the "Methodology on the Determination of System Loss Caps", hereto
attached as Annex "B" and made an integral part of this Resolution;
NOW, THEREFORE, the ERC, after thorough and due
deliberation, hereby RESOLVES, as it is hereby RESOLVED, to
APPROVE and ADOPT, the Rules for Setting the Distribution System
Loss Cap and Establishing Performance Incentive Scheme for Distribution
Efficiency attached as Annex "A" of this resolution and the new caps shall
be effective starting May
2018
billing.
Resolution No.
20
________, Series of 2017
A Resolution Adopting the ERC Rules for Setting the Distribution System toss Cap
and Establishing Performance Incentive Scheme for Distribution .fficiency
Page 3 of 3
This Resolution shall take effect after fifteen (15) days following the
completion of its publication in a newspaper of general circulation in the
Philippines or in the Official Gazette.
Let copies of this Resolution be furnished the University of the
Philippines Law Center-Office of the National Administrative Register
(UPLC-ONAR), the Senate Committee on Energy, the House of
Representatives Committee on Energy, the Department of Energy (DOE),
and all Distribution Utilities.
Pasig City,
05
December
2017.
AGNES VST EVANADERA
Chaimet/son and CEO
ALFREDO J. NON
GI1LORIAVICTORVY C. YAP- TARUC
Commissioner
JOSEFINA PAT/laIXA. MAGPALE- ASIRIT
chhhiissioner
ROS-SCMD/T4EM/LLG/FBp
Commissioner
~ERONIMO D. STA. ANA
I
Commissioner
/
&
ANNEX “A”
Rules for Setting the
Distribution System Loss Cap
And Establishing Performance
Incentive Scheme for
Distribution Efficiency
Final Rules
05 December 2017
1|Page
Table of Contents
I.
General Provisions ............................................................................................................................. 5
1.1 Background ................................................................................................................................. 5
1.2 Purpose ........................................................................................................................................ 6
1.3 Scope ............................................................................................................................................ 6
1.4 Construction of the Rules .......................................................................................................... 6
1.5 Definition of Terms .................................................................................................................... 6
1.6 Provision of Information ......................................................................................................... 10
1.7 Computation of Distribution System Loss............................................................................ 10
II. Distribution System Loss Caps ...................................................................................................... 11
2.1 Electric Cooperatives Clusters ................................................................................................ 11
2.2 Distribution System Loss Caps for Electric Cooperatives .................................................. 12
2.3 Distribution System Loss Caps for Private Distribution Utilities...................................... 12
2.4 Distribution System Loss Recoverable through System Loss Charge............................... 13
III. Performance Incentive Scheme ..................................................................................................... 13
3.1 General Provisions for the PIS ............................................................................................... 13
3.2 Performance Incentive Scheme for Electric Cooperatives ................................................. 14
3.3 PIS for Private Distribution Utilities ..................................................................................... 15
IV. Application for Individualized Distribution System Loss Caps ................................................. 17
4.1 General Provisions for the Individualized Distribution System Loss Cap ....................... 17
4.2 Technical Loss Component of the Individualized DSL Cap ............................................... 17
4.3 Non-Technical Loss component of the Individualized DSL Cap ....................................... 18
V.
Reportorial Requirements .............................................................................................................. 19
5.1 Regular Review by the Energy Regulatory Commission .................................................... 19
5.2 Incomplete Submission or Non-Submission of Documents .............................................. 20
VI. Final Provisions ................................................................................................................................ 20
6.1 Exception from the Provisions of this Rules ........................................................................ 20
6.2 Regulatory Costs ....................................................................................................................... 20
6.3 Effect of the New System Loss Cap under this Rules on DU’s Existing Cap .................... 20
6.4 Repealing/Separability Clause ............................................................................................... 20
6.5 Effectivity................................................................................................................................... 20
2|Page
ANNEX A: Methodology for Segregating DSL ..................................................................................... 21
A.1 Introduction .............................................................................................................................. 21
A.2 Components of Distribution System Loss ............................................................................ 21
A.3 Calculation of Distribution System Loss ............................................................................... 22
A.4 Distribution Network Models ................................................................................................. 26
A.5 Distribution Load Models ....................................................................................................... 30
A.6 Data Requirements .................................................................................................................. 32
ANNEX B: Reportorial Requirement Guidelines ................................................................................ 38
B.1 Monthly Sub-Transmission and Substation DSL Data ....................................................... 38
B.2 Monthly Feeder DSL Data....................................................................................................... 63
B.3 Energy Quantities, Network Parameters, and CAPEX/OPEX Programs ......................... 80
ANNEX C: ERC Prescribed Templates
C.1 Subtransmission and Substation Data DSL Template
C.2 Feeder Data DSL Template
C.3 DU Annual Reportorial Requirements Template
3|Page
List of Tables
Table 1. Electric Cooperatives Cluster 1 ................................................................................................ 11
Table 2. Electric Cooperatives Cluster 2 ............................................................................................... 11
Table 3. Electric Cooperatives Cluster 3 ............................................................................................... 12
Table 4. Distribution Feeder Loss Cap for ECs .................................................................................... 12
Table 5. Distribution Feeder Loss Cap for PDUs ................................................................................. 12
Table 6. Performance Assessment Factor Computation for ECs ....................................................... 15
Table 7. PIS Structure Thresholds for ECs (% System Loss).............................................................. 15
Table 8. Performance Assessment Factor Computation for PDUs ................................................... 16
Table 9. PIS Structure Thresholds for Private DUs ............................................................................. 16
Table 10. ERC Customer Class Values................................................................................................... 83
Table 11. DU Customer Type Values ...................................................................................................... 83
Table 12. Sample Customer Class Template ......................................................................................... 83
Table 13. ERC Customer Class Values ................................................................................................... 85
Table 14. DU Customer Type Values ..................................................................................................... 85
Table 15. Sample Customer Class Template ......................................................................................... 85
Table 16. Expenditure Type Values........................................................................................................ 87
Table 17. Target Loss Components Values ........................................................................................... 87
Table 18. Month Values ........................................................................................................................... 88
List of Figures
Figure 1. Reward Structure of the PIS for Electric Cooperatives ....................................................... 14
Figure 2. Reward Structure of the PIS for Private Distribution Utilities ......................................... 15
Figure 3. Conductor Arrangement ......................................................................................................... 42
Figure 4. Bundling of Conductors .......................................................................................................... 44
Figure 5. Conductor Spacing .................................................................................................................. 45
Figure 6. Spacing of Phase Conductors and Ground Wire ................................................................. 45
Figure 7. Distance between Ground Wires ........................................................................................... 45
Figure 8. Distance between Circuit 1 and Circuit 2 ............................................................................. 46
Figure 9. Height of Phase Conductors and Ground Wires ................................................................. 46
Figure 10. Constructional Data of Underground Cable ...................................................................... 48
Figure 11. Conductor Arrangement........................................................................................................ 58
4|Page
I.
General Provisions
1.1 Background
Section 38 of Republic Act No. 9136, otherwise known as the Electric Power
Industry Reform Act of 2001 or EPIRA, created the Energy Regulatory
Commission (ERC) as an independent quasi-judicial regulatory body.
Under Section 43 of the EPIRA, the ERC is tasked to promote competition,
encourage market development, ensure customer choice and penalize abuse
of market power in the electricity industry. To carry out this undertaking,
the ERC shall promulgate necessary rules and regulations, including
Competition Rules, and impose fines or penalties for any non-compliance
with or breach of the EPIRA, its Implementing Rules and Regulations, and
other rules and regulations which it promulgates or administers as well as
other laws it is tasked to implement and enforce.
Likewise, Section 43 (f) of the EPIRA provides:
“xxx. To achieve this objective and to ensure the complete removal of
cross subsidies, the cap on the recoverable rate of system losses
prescribed in Section 10 of Republic Act No. 7832, is hereby amended
and shall be replaced by caps which shall be determined by the ERC
based on load density, sales mix, cost of service, delivery voltage and
other technical considerations it may promulgate. xxx”
Pursuant to Section 43 (f) of the EPIRA, the ERC shall establish and enforce
a methodology for setting transmission and distribution wheeling rates and
retail rates for the captive market of a distribution utility, taking into
account all relevant considerations, including the efficiency and inefficiency
of the regulated entities. To achieve the said objective, the cap on the
recoverable rate of system loss prescribed in Section10 of Republic Act No.
7832 is amended and shall be replaced by caps which shall be determined by
the ERC based on load density, sales mix, cost of service, delivery voltage
and other technical considerations it may promulgate.
In view thereof, the Regulatory Operations Service (ROS), specifically its
Standards and Compliance Monitoring Division (SCMD), being at the
forefront in recommending various standards to be promulgated and
enforced by the ERC and to be followed and observed by stakeholders in the
electric power industry, is tasked to determine the applicable Distribution
System Loss (DSL) Caps.
5|Page
1.2 Purpose
This Rules for Setting the Distribution System Loss Cap and Establishing
Performance Incentive Scheme for Distribution Efficiency embodies the
new regulatory framework for all Distribution Utilities (DUs) that is
designed to achieve the following:
a. Determine reasonable DSL Caps for all DUs based on technical criteria
and objectives given in the EPIRA;
b. Align the new DSL Caps with the existing Performance Incentive
Schemes (PIS) that promote efficient operation and service of the DUs;
and
c. Promote submission from the DUs of comprehensive information
relevant to DSL.
1.3 Scope
This Rules shall apply to all DUs, whether Electric Cooperative (EC) or
Private Distribution Utility.
1.4 Construction of the Rules
This Rules shall be construed to promote the objective of securing a just,
speedy, and inexpensive disposition of the proceedings for promulgating the
DSL Caps and the PIS for the DUs.
1.5 Definition of Terms
The following words and phrases as used in this Rules shall have the
meanings set forth below:
TERM
DEFINITION
Captive Customer
A Customer who does not have the choice of
supplier of electricity, as determined by the ERC
in accordance with EPIRA.
Those assets that are put in place primarily to
connect a Distribution Utility to the Transmission
System and used for purposes of transmission
connection services for the conveyance of
electricity, which if taken out of the system will
only affect the Distribution Utility connected to it
and will have minimal effect on the Transmission
System and other entities connected to the
Transmission System.
A Customer who has the choice of supplier of
electricity, as determined by the ERC in
accordance with EPIRA.
A person or entity supplied with electric service
under a contract with the Distribution Utility. For
the purpose of this Rules, no distinction shall be
made between Captive Customers and Contestable
Customers, provided they are served through the
Distribution System of the Distribution Utility.
The charges for distribution, supply, metering and
other related charge and adjustments.
Connection Assets
Contestable
Customer
Customer
Distribution
Charge
6|Page
TERM
Distribution
Feeder Loss
Distribution
System
DEFINITION
This is the sum of Feeder Technical Loss and NonTechnical Loss.
The system of wires and associated facilities that
belong to a franchised Distribution Utility,
extending between the delivery points on the
Transmission or Sub-Transmission System or
generator connection and the point of connection
to the premises of the End-User.
Distribution
The electric Energy Input minus the electric
System Loss
Energy Output for a specified billing period or set
(DSL)
of billing periods.
Distribution
Any Electric Cooperative, private corporation,
Utility (DU)
government-owned utility, or existing local
government unit, which has an exclusive franchise
to operate a Distribution System in accordance
with its franchise and EPIRA.
Distribution
The aggregate of energy used for the proper
Utility Use
operation of the distribution system.
DSL Cap
The level of Distribution System Loss recoverable
from Customers.
DSL Data
The Distribution System data containing
information that can be used to simulate the
Technical Loss, and is described under Annex A of
this Rules.
Electric
A Distribution Utility organized pursuant to
Cooperative (EC)
Presidential Decree No. 269, as amended, or
otherwise provided in EPIRA.
Embedded
Generating Units that is indirectly connected to
Generators
the Grid through the Distribution Utilities’ lines or
industrial generation facilities that are
synchronized with the Grid. For the purpose of
this Rules, this term shall include a Generating
Plant that is connected to an Isolated Distribution
System.
Energy
The integral of electrical power with respect to
time and is measured in kilowatt-hours (kWh).
Energy Input
Energy delivered to the Distribution System by the
Transmission System, Embedded Generators,
other Distribution Systems, and User Systems
with generating facilities.
Energy Output
Energy delivered to the Users of the Distribution
System, including the Energy for Distribution
Utility Use.
Energy Regulatory The independent quasi-judicial regulatory body
Commission
created under EPIRA.
(ERC)
Entrant Group
A group of Distribution Utilities entering a
regulatory program at the same time, as defined in
ERC Resolution No. 10, Series of 2010 for Private
DUs or in ERC Resolution No. 8, Series of 2011 for
Electric Cooperatives.
EPIRA
Republic Act No. 9136, otherwise known as the
Electric Power Industry Reform Act of 2001.
Equipment
All apparatus, machines, and conductors, among
others, that are used as a part of or in connection
with an electrical installation.
7|Page
TERM
Feeder Technical
Loss
Generating Plant
Generating Units
Grid
Higher Voltage
Customer (HV or
MV Customer)
Isolated
Distribution
System
Low Voltage
Customer (LV
Customer)
Non-Technical
Loss (NTL)
Off-Grid EC
On-Grid EC
Peak Power
Demand
Performance
Incentive
Schemes (PIS)
Philippine
Distribution Code
(PDC)
Primary
Distribution
System
8|Page
DEFINITION
The sum of the Technical Losses associated with
the Primary Distribution System and the
Secondary Distribution System.
A facility consisting of one or more Generating
Units.
A conversion apparatus, including auxiliaries and
associated Equipment, that function as a single
unit and is used to produce electric Energy from
some other form of Energy.
The high voltage backbone System of
interconnected transmission lines, substations,
and related facilities, located in each of Luzon,
Visayas, and Mindanao, or as may be determined
by the ERC in accordance with Section 45 of the
EPIRA.
A Customer that is connected to and served
through the Sub-Transmission System or the
Primary Distribution System.
The backbone system of wires and associated
facilities that are not directly connected to any one
of the national Transmission Systems of Luzon,
Visayas, or Mindanao.
A Customer that is not a Residential Customer and
is connected to and served through the Secondary
Distribution System.
The aggregate of Energy lost due to pilferage,
meter reading errors, meter tampering, and any
Energy loss that is not related to the physical
characteristics and functions of the electric
system.
An Electric Cooperative that operates an Isolated
Distribution System.
An Electric Cooperative that operates a
Distribution System that is connected to any one
of the national Transmission Systems in Luzon,
Visayas, or Mindanao.
The maximum value of power, measured in MW,
required by the Distribution Utility for a specific
billing period or set of billing periods.
Mechanism designed to incentivize the
Distribution Utility to improve its performance.
For the purpose of this Rules, performance shall
be in terms of distribution efficiency measured
through Distribution System Loss.
A compilation of rules and regulations that govern
the Distribution Utilities in the operation and
maintenance of their Distribution Systems, which
includes, among others, standards for service and
performance, and defines and establishes the
relationship of the Distribution Systems with the
facilities or installations of the parties connected
thereto.
A portion of the Distribution System delineated by
the secondary side of the Substation transformer
and the primary side of all Distribution
transformers.
TERM
DEFINITION
Private
Distribution
Utility (PDU)
Reference
Distribution
Network
Regulatory Period
A Distribution Utility that is operated by a private
corporation.
Republic Act No.
7832
Residential
Customer
Secondary
Distribution
System
Secondary Line
Sub-Transmission
and Substation
Loss
Sub-Transmission
and Substation
Technical Loss
Sub-Transmission
System
System
System Loss
Charge
System Loss Rate
Technical Loss
(TL)
Three-Phase
Power Flow
Transmission
System
User
User System
9|Page
An idealized version of the Distribution System,
formulated as prescribed in Section 4 of this
Rules.
A period of time over which the rates of the
Distribution Utility is defined under a set of rules
issued by the ERC.
The law otherwise known as the Anti-electricity
and Electric Transmission Lines/Materials
Pilferage Act of 1994.
A Customer that is residential in nature and
connected to and served through the Secondary
Distribution System.
A portion of the Distribution System that is at the
secondary side of a Distribution transformer.
A Distribution line connected at the Secondary
Distribution System.
This is the sum of Sub-Transmission System and
Substation Technical Losses and Non-Technical
Loss.
The sum of the Technical Losses associated with
the Sub-Transmission System and Distribution
substations.
The portion of the Distribution System that is
delineated by the connection point to the
Transmission System and the primary side of all
Substation transformers.
A group of components connected or associated in
a fixed configuration to perform a specific
function.
The charge representing recovery of the cost of
power due to Distribution System Loss.
The rate determined in accordance with ERC
Resolution No. 16, Series of 2009 and any
amendments thereto.
The component of Distribution System Loss that is
inherent in the physical delivery of electric
Energy. It includes conductor loss, transformer
core loss, and technical error in meters.
An analytical tool that simulates the power flows
in an unbalanced three-phase Distribution
System.
Has the same definition as “Grid”.
A person or entity that uses the Distribution
System and related distribution facilities.
A System owned or operated by a User of the
Distribution System.
1.6 Provision of Information
The results and findings presented in this Rules utilized information
provided by the DUs through the ERC. For the purpose of this Rules,
supplementary information, calculations, and data may be required as
deemed necessary by the ERC.
1.7 Computation of Distribution System Loss
1.7.1
The Technical Loss and Non-Technical Loss shall be calculated using
the methodology described in Annex A: Methodology for
Segregating Distribution System Losses of this Rules.
1.7.2 The Distribution Utility Use shall be treated as an operation and
maintenance expense of the DU.
1.7.3 In determining the boundaries of the Distribution System for
calculating the DSL, the definition of asset boundaries under Annex
A: Amended Rules on the Definition and Boundaries of Connection
Assets for Customers of Transmission Provider of ERC Resolution
No. 23, Series of 2016 shall prevail. For the avoidance of doubt, this
means that the Distribution System shall include the Connection
Assets for the DU, even if these are not owned by the DU.
1.7.4 For the purpose of this Rules, no distinction shall be made between a
Captive Customer and a Contestable Customer. They shall be
considered Customers insofar as they are served through the
Distribution System of the DU.
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II.
Distribution System Loss Caps
2.1 Electric Cooperatives Clusters
2.1.1
For the DSL Caps, the following clusters of Electric Cooperatives are
set as shown in Table 1 to Table 3.
Table 1. Electric Cooperatives Cluster 1
Cluster 1
BANELCO
MASELCO
BASELCO
MOPRECO
BATANELCO OMECO
BISELCO
ORMECO
CASELCO
PALECO
CELCO
PROSIELCO
DIELCO
ROMELCO
FICELCO
SIARELCO
IFELCO
SIASELCO
KAELCO
SULECO
LUBELCO
TAWELCO
MARELCO
TIELCO
MARIPIPI
TISELCO
Table 2. Electric Cooperatives Cluster 2
ABRECO
AKELCO
ALECO
ANECO
ANTECO
ASELCO
AURELCO
BATELEC I
BENECO
BILECO
BOHECO I
BOHECO II
BUSECO
CAGELCO I
CAGELCO II
CAMELCO
CANORECO
CAPELCO
11 | P a g e
CASURECO I
CASURECO II
CASURECO III
CASURECO IV
CEBECO I
CEBECO II
CEBECO III
CENPELCO
COTELCO
DANECO
DASURECO
DORECO
ESAMELCO
FIBECO
FLECO
GUIMELCO
ILECO I
ILECO II
Cluster 2
ILECO III
INEC
ISECO
ISELCO I
ISELCO II
LANECO
LASURECO
LEYECO I
LEYECO III
LEYECO IV
LEYECO V
LUELCO
MAGELCO
MOELCI I
MOELCI II
MORESCO II
NEECO I
NEECO II - AREA I
NEECO II - AREA II
NOCECO
NONECO
NORECO I
NORECO II
NORSAMELCO
NUVELCO
PANELCO I
PANELCO III
PELCO I
PELCO II
PELCO III
PRESCO
QUEZELCO I
QUEZELCO II
QUIRELCO
SAJELCO
SAMELCO I
SAMELCO II
SOLECO
SORECO I
SORECO II
SUKELCO
SURNECO
SURSECO I
SURSECO II
TARELCO I
TARELCO II
ZAMECO I
ZAMECO II
ZAMSURECO I
ZAMSURECO II
ZANECO
Table 3. Electric Cooperatives Cluster 3
Cluster 3
BATELEC II
MORESCO I
PENELCO
SOCOTECO I
CENECO
LEYECO II
SOCOTECO II
ZAMCELCO
2.2 Distribution System Loss Caps for Electric Cooperatives
2.2.1 For Electric Cooperatives, the Distribution Feeder Loss Cap shall be
as shown in Table 4.
Table 4. Distribution Feeder Loss Cap for ECs
Year
Cluster 1
Cluster 2
Cluster 3
2018
12.00 %
12.00 %
12.00 %
2019
12.00 %
11.00 %
11.00 %
2020
12.00 %
10.25 %
10.00 %
2021
12.00 %
10.25 %
9.00 %
2022 onwards
12.00 %
10.25 %
8.25 %
2.2.2 For Electric Cooperatives whose service area is composed of on-grid
and off-grid areas, the Distribution Feeder Loss Cap for the on-grid
area shall be that of the assigned cluster while the Distribution
Feeder Loss Cap for the off-grid area shall be based on Cluster 1.
2.3 Distribution System Loss Caps for Private Distribution Utilities
2.3.1 For Private Distribution Utilities (PDUs), the Distribution Feeder
Loss Cap shall be as shown in Table 5.
Table 5. Distribution Feeder Loss Cap for PDUs
Year
Private DUs
2018
6.50 %
2019
6.25 %
2020
6.00 %
2021
5.50 %
2.3.2 The Distribution Feeder Loss Caps for Private Distribution Utilities
shall be reviewed in 2021. A Private Distribution Utility who fails to
submit at the minimum one-year’s (from 2018 to 2020) worth of all
the data described in Section 5.1 of the Rules, shall be excluded from
the review and assigned a Distribution Feeder Loss cap of 4.75% by
2022 onwards.
12 | P a g e
2.4 Distribution System Loss Recoverable through System Loss
Charge
2.4.1 The level of Distribution System Loss that a Distribution Utility may
recover from its Customers through System Loss Charge shall not
exceed the sum of:
a. The actual Sub-Transmission and Substation Loss
and
;
b. The actual sum of Non-Technical Loss (NTL) and Feeder
Technical Loss (TLfdr), or the Distribution Feeder Loss cap
(DSLfdr,cap), whichever is lower.
{
}
Where,
SLSysLossCharge = Total Distribution System Loss that can be
recovered through the System Loss Charge, in
percent;
DSLST+SS
= Sub-Transmission and Substation Loss, in percent;
TLfdr
= Feeder Technical Loss, in percent;
NTL
= Non-Technical Loss, in percent; and
DSLfdr,cap
= Distribution Feeder Loss cap, in percent.
2.4.2 Distribution Utilities shall submit the Monthly Sub-Transmission and
Substation DSL Data.
2.4.3 Sub-Transmission and Substation Loss
shall be computed
using actual metered quantities. It shall be set to 0.00 for nonsubmission of the Monthly Sub-Transmission and Substation DSL
Data by the DU.
2.4.4 In the absence of Metered
data submitted by the DU, the
Distribution Feeder Loss (DSLfdr) shall be set to 0.00.
III.
Performance Incentive Scheme
3.1 General Provisions for the PIS
3.1.1
The goals of the Performance Incentive Scheme (PIS) are to: (1)
reduce the costs of DSL passed on to Customers and (2) promote
efficiency in Distribution Systems over the long-term. The PIS is
intended to motivate DUs to reduce the Technical Losses and NonTechnical Losses in Distribution Systems.
3.1.2 The PIS shall involve a price-linked reward for DUs. The reward shall
be a percentage of the Distribution Charge.
3.1.3 The Distribution Feeder Loss to be used for the PIS shall be
computed based on the actual Distribution Feeder Loss for the most
recent 12-month period.
13 | P a g e
3.1.4 The reward under the PIS for distribution efficiency is separate from
and does not affect the System Loss Rate that the Distribution Utility
can pass on to its Customers through the System Loss Charge.
3.2 Performance Incentive Scheme for Electric Cooperatives
3.2.1 This Section 3.2 applies exclusively to Electric Cooperatives.
3.2.2 The PIS reward structure for ECs shall be as shown in Figure 1, with
three regions, in order of improving distribution efficiency: (1) no
reward, (2) increasing reward, and (3) maximum reward.
Figure 1. Reward Structure of the PIS for Electric Cooperatives
3.2.3 The distribution feeder loss component of the performance incentive
factor (S) shall be computed in the following manner:
Where,
=
=
=
Performance incentive for Distribution Feeder
Loss for year t;
Weight assigned to Distribution Feeder Loss
performance; and
Performance Assessment Factor for
Distribution Feeder Loss in the previous year.
3.2.4 Based on the value of the actual total DSLfdr and its relationship with
the various thresholds in the PIS reward structure for ECs, the value of
the Performance Assessment Factor
shall be
determined in the manner shown in Table 6.
3.2.5 The values of the thresholds (a and b) in the PIS structure for each
cluster of electric cooperatives are shown in Table 7.
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Table 6. Performance Assessment Factor Computation for ECs
PIS Region (ECs)
Maximum reward
Proportional
reward
Value of DSLfdr
Value of
a ≥ DSLfdr
b ≥ DSLfdr >a
Deadband region
(
)
DSLfdr >b
DSLfdr = Non-Technical Loss + Feeder Technical Loss
Table 7. PIS Structure Thresholds for ECs (% System Loss)
Threshold
Cluster 1
Cluster 2
Cluster 3
A
8.50%
7.75%
6.00%
B
12.00%
10.25%
8.25%
3.2.6 The thresholds of the PIS structure shall be used by the Commission in
its setting of the maximum price-linked incentive for ECs.
3.3 PIS for Private Distribution Utilities
3.3.1 This Section 3.3 applies exclusively to Private Distribution Utilities.
3.3.2 The PIS reward structure for Private DUs shall be as shown in
Figure 2, with three regions, in order of improving distribution
efficiency: (1) no reward, (2) increasing reward, and (3) maximum
reward.
Figure 2. Reward Structure of the PIS for Private Distribution Utilities
3.3.3 The system loss component of the performance incentive factor (St)
shall be computed in the following manner:
Where,
=
=
=
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Performance incentive for Distribution Feeder
Loss for year t;
Weight assigned to Distribution Feeder Loss
performance; and
Performance Assessment Factor for Distribution
Feeder Loss in the previous year.
3.3.4 Based on the value of the actual total
and its relationship with
the various thresholds in the PIS structure for Private DUs, the value
of the Performance Assessment Factor
shall be
determined in the manner shown in Table 8.
3.3.5 The values of the thresholds (a and b) in the PIS reward structure for
Private DUs are shown in Table 9.
Table 8. Performance Assessment Factor Computation for PDUs
PIS Region
Value of
Maximum reward
a≥
Proportional
reward
Deadband region
b≥
Value of
>a
(
>b
DSLfdr = Non-Technical Loss + Feeder Technical Loss
Table 9. PIS Structure Thresholds for Private DUs
Threshold
% System Loss
a
3.50%
b
4.75%
3.3.6 The thresholds of the PIS structure shall be used by the Commission in
the next setting of the maximum price-linked incentive for Private
DUs.
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)
IV.
Application for Individualized DSL Caps
4.1 General Provisions for the Individualized DSL Cap
4.1.1
A Distribution Utility may elect to use an alternative method for
determining an individualized DSL Cap that shall be applied to it.
This section of the Rules is intended to provide the framework for
such a method.
4.1.2 The individualized DSL Cap shall have two components: one for
Technical Loss and another for Non-Technical Loss in accordance
with the prescribed methodologies in this Rules.
4.1.3 If a Distribution Utility has elected for an individualized DSL cap (or
a component thereof), it may continue to use the existing cap subject
to prior approval of the Commission.
4.1.4 In case a DU fails to seek a provisional authority for the exemption or
Individualized DSL Cap, the applicable DSL Cap to the said DU shall
be the cap of the cluster it belongs.
4.1.5 In determining the reasonable level of individualized DSL Cap, costs
and benefits must be analyzed from the viewpoint of the Customer.
4.2 Technical Loss Component of the Individualized DSL Cap
4.2.1 In determining the Technical Loss component of the individualized
DSL Cap, the DU shall develop its Reference Distribution Network.
The Reference Distribution Network is the Distribution System with
equipment capacities selected to minimize the total cost, and serves
the Customers of the DU while meeting all relevant performance
standards.
4.2.2 For each segment of the Reference Distribution Network, the total
cost shall include capital expenditures, operating and maintenance
expenditures, the cost of Technical Loss, and all other associated
costs. In deciding the appropriate size for each segment, the DU may
consider load forecasts and associated costs up to the expected
economic life of the segment (for example, 30 years for distribution
lines). For segments where special considerations must be made (for
example, in segments where one type of conductor is favored due to
environmental considerations), the DU must be able to justify these.
4.2.3 To the extent possible, the characteristics of the load of the Reference
Distribution Network shall have the same characteristics (in terms of
location and load behavior) as the Customers of the Distribution
Utility.
4.2.4 In determining the Technical Loss component of the individualized
DSL Cap, the DU may use load forecasts up to the end of the next
Regulatory Period.
17 | P a g e
4.2.5 For each year, from the test year to the end of the next Regulatory
Period, the Technical Loss of the Reference Distribution Network
shall be determined based on load flow simulations. If the load flow
simulations show that there are voltage violations in the distribution
network, the DU must first correct these in the model through
selection of appropriate sizes of distribution lines and distribution
transformers, application of corrective equipment such as automatic
voltage regulators and capacitors, or change in nominal system
voltages, among others.
4.2.6 The Technical Loss component of the individualized DSL Cap shall be
based on the maximum value of the Technical Loss obtained over all
relevant periods for the Reference Distribution Network.
4.3 Non-Technical Loss component of the Individualized DSL Cap
4.3.1 In determining the reasonable level of the Non-Technical Loss
component of the individualized DSL Cap, the DU shall first
determine two cost curves as functions of the Non-Technical Loss:
the NTL Cost Curve and the NTL Reduction Cost Curve.
4.3.2 The NTL Cost Curve represents the cost of Non-Technical Loss to
Customers, assuming these costs are pass-through.
4.3.3 The NTL Reduction Cost Curve represents the cost that the DU
expects to incur to achieve a certain level of Non-Technical Loss.
4.3.4 The NTL Total Cost Curve shall be calculated as the sum of the NTL
Cost Curves and the NTL Reduction Cost Curve, also expressed as a
function of the Non-Technical Loss. The level of Non-Technical Loss
at which the NTL Total Cost Curve is the minimum shall serve as the
basis for the Non-Technical Loss component of the individualized
DSL Cap.
4.3.5 In case a practicality issue arises (for example, if required resources
to meet the optimal value of the Non-Technical Loss that are outside
the control of the Distribution Utility cannot be mobilized in time
within the next Regulatory Period), the DU must justify using a
different value for the Non-Technical Loss component of the
individualized DSL Cap.
18 | P a g e
V.
Reportorial Requirements
5.1 Regular Review by the Energy Regulatory Commission
The Distribution Utility shall submit the following documents and data for
the review and verification of the ERC:
1. Monthly DSL data for the Sub-Transmission network (including
Connection Assets), the Customers connected to the Sub-Transmission
network, and the distribution substations encoded according to the ERCprescribed template. Refer to Annex B Section B.1 of this Rules for the
data description. This DSL sub-transmission data in MS Excel format
shall be submitted on or before the 30th day of the following month.
2. Monthly DSL data per feeder for the whole coverage area encoded
according to the ERC-prescribed template. Refer to Annex B Section B.2
of this Rules for the data description. This DSL feeder data in MS Excel
format shall be submitted on or before the 30th day of the following
month.
3. Annual summary of Energy quantities and relevant network parameters
such as the following:
a.
b.
c.
d.
e.
f.
g.
h.
i.
j.
k.
l.
m.
n.
o.
p.
q.
r.
Total Energy Input, in kWh;
Total Energy Output, in kWh;
Distribution Utility Use, in kWh;
Total Number of Substations;
Total Number of Feeders;
Total Number of Customers;
Peak Demand, in MW;
Total Circuit Length of Primary Lines, in meters;
Total Circuit Length of Secondary Lines, in meters;
Total System Loss, in kWh;
Sub-Transmission and Substation Loss, in kWh;
Feeder Technical Loss, in kWh;
Non-Technical Loss, in kWh;
Total Energy Output for each Customer class, in kWh (e.g., HV
Customers, LV Customers, and Residential Customers);
Total Number of Customers per Customer class, in kWh (e.g., HV
Customers, LV Customers, and Residential Customers);
List of CAPEX and OPEX programs related to the Technical Loss and
Non-Technical Loss reduction programs;
DU Use Load Data; and
Actual Segregated DSL Data.
Refer to Annex B Section B.3 of this Rules for the data descriptions.
This annual data (in MS Excel format) from the previous year shall be
submitted by the end of May of the current year.
4. Monthly submission of actual Sub-Transmission Line and Substation
single line diagram with the location of billing meter/s, including feeder
metering, and any changes therein. In the alternative, a DU may submit
a sworn statement that no changes/modifications were made. This data
in PDF format shall be submitted on or before the 30th day of the
following month.
19 | P a g e
5. Monthly submission of power supply bill/s and supporting documents.
This data in PDF format shall be submitted on or before the 30th day of
the following month.
5.2 Incomplete Submission or Non-Submission of Documents
The Distribution Utility shall be issued fines and penalties for incomplete
submission or non-submission of the documents and data described in
Section 5.1 of this Rules. The ERC Resolution No. 03, Series of 2009 (A
Resolution Amending the Guidelines to Govern the Imposition of
Administrative Sanctions in the Form of Fines and Penalties Pursuant to
Section 46 of Republic Act No. 9136), and any amendments thereto shall
apply.
VI.
Final Provisions
6.1 Exception from the Provisions of this Rules
Where good cause appears, the Commission may allow an exception from
any provision of this Rules, if such exception is found to be in public interest
and is not contrary to the law, rules and regulations.
6.2 Regulatory Costs
All Distribution Utilities shall bear the regulatory implementation costs or
costs associated with the implementation of this Rules, including but not
limited to, costs attendant to the public hearings in the DU’s localities.
6.3 Effect of the New System Loss Cap under this Rules on DU’s
Existing Cap
The DSL Caps determined under this Rules shall supersede the existing
approved cap of the DUs and mandatory bind them to adopt this new loss
cap, except as otherwise provided herein.
6.4 Repealing/Separability Clause
6.4.1 All existing Rules or any part thereof which are inconsistent with this
Rules are hereby repealed, amended or modified accordingly.
6.4.2 If any provision or part of a provision of this Rules is declared invalid
or unconstitutional by a court of competent jurisdiction, those
provisions which are not affected thereby shall continue to be in full
force and effect.
6.5 Effectivity
This Rules shall take effect on the billing month of ________ 2018.
20 | P a g e
ANNEX A: Methodology for Segregating DSL
A.1
Introduction
This document describes the methodology for segregating Distribution System
Loss according to its various components and various occurrences throughout the
distribution network. The methodology presented is consistent with the
methodology which is part of the Guidelines for the Application and Approval of
Caps on the Recoverable Rate of Distribution System Losses (ERC 2004). In
addition, this document enhances the previous document as follows: (a)
recognizing Distribution Utility Use as the aggregate energy used for the proper
operation of the distribution system which is consistent with ERC Resolution No.
17 Series of 2008, thus replacing the term Administrative Loss; (b) providing
instructions that Sub-Transmission Technical Loss shall be computed separate
from the Feeder Technical Loss and Non-Technical Loss. Other minor revisions
to maintain consistent writing style were also applied accordingly.
A.2
Components of Distribution System Loss
Distribution System Loss shall be segregated into the following components:
a.
b.
c.
Sub-Transmission and Substation Technical Loss;
Feeder Technical Loss; and
Non-Technical Loss.
Technical Loss is the component of Distribution System Loss that is inherent in
the electrical equipment, devices and conductors used in the physical delivery of
electric energy. It includes the Load Losses and No-Load Losses (or fixed losses)
in the following:
a.
b.
c.
d.
e.
f.
g.
h.
i.
j.
k.
Sub-Transmission Lines;
Substation Power Transformers;
Primary Distribution Lines;
Voltage Regulators;
Capacitors;
Inductors or Reactors;
Distribution Transformers;
Secondary Distribution Lines;
Service Drops; and
Metering Equipment and Instrument Transformers;
All other electrical equipment necessary for the operation of the
Distribution System.
Sub-Transmission and Substation Technical Loss is the technical loss incurred by
the sub-transmission lines, substation transformers, and associated network
elements of the Distribution Utility. Feeder Technical Loss is the technical loss
incurred by the primary and secondary distribution network of the Distribution
Utility.
21 | P a g e
Non-Technical Loss is the component of Distribution System Loss that is not
related to the physical characteristics and functions of the electrical system, and
is caused primarily by human error, whether intentional or not. Non-Technical
Loss includes the electric energy lost due to pilferage, tampering of meters,
erroneous meter reading, and erroneous billing. For the purpose of segregating
Distribution System Losses, the Load Loss due to electric energy pilferage shall
be considered part of the Non-Technical Loss.
A.3
Calculation of Distribution System Loss
A.3.1 Calculation Period
Distribution System Loss shall be calculated monthly and shall coincide
with the Billing Cycle adopted by the Distribution Utility. The Distribution
Utility shall report the total number of days, total number of hours, and
the inclusive dates covered by the Billing Cycle used as the period for
calculating the Distribution System Loss.
A.3.2 Total Distribution System Loss
Distribution System Loss shall be computed as the difference between the
Total Electric Energy Input and the Total Electric Energy Output during
the Billing Period. The Total Electric Energy Input shall include all electric
energy delivered to the Distribution System by the Transmission System,
by Embedded Generators, by other Distribution Systems, and by User
Systems with generating units. The Total Electric Energy Output shall
include all electric energy delivered to the Users of the Distribution System
and the electric energy for Distribution Utility Use.
In equation form, the Total Distribution System Losses shall be computed
as follows:
Equation A.1. Total Distribution System Loss
∑
∑
∑
∑
∑
A.3.3 Distribution Utility Use
Distribution Utility Use accounts for the electric energy used by the
Distribution Utility in the proper operation of the Distribution System.
This includes the electric energy consumption of connected essential
electrical loads in the following facilities, subject to the approval by the
ERC:
22 | P a g e
a.
b.
c.
d.
Distribution Substations;
Offices of the Distribution Utility;
Warehouses and Workshops of the Distribution Utility; and
Other essential electrical loads of the Distribution Utility.
Distribution Utility Use shall be the sum of actual electric energy
consumption of the essential loads used by the facilities of the Distribution
Utility during the Billing Period.
In equation form, the Distribution Utility Use shall be calculated as
follows:
Equation A.2. Distribution Utility Use
∑
∑
∑
A.3.4 Sub-Transmission and Substation Technical Loss
The Sub-Transmission and Substation Technical Loss for the Billing
Period shall be the sum of the hourly Load Losses and No-Load Losses
incurred by the sub-transmission network and the distribution
substations. It shall be calculated based on Load Flow simulations of the
sub-transmission network and distribution substations using the
appropriate network models and load models. The Load Flow simulations
must capture the Technical Loss from the metering point associated with
the root branch of the sub-transmission network to the root branch of the
medium-voltage distribution feeders (typically at the secondary of the
Distribution Substation transformer).
In equation form, the Sub-Transmission and Substation Technical Loss
shall be computed as follows:
Equation A.3 Sub-Transmission and Substation Technical Loss
∑
∑
∑
∑
∑
∑
∑
∑
∑
23 | P a g e
A.3.5 Feeder Technical Loss
The Feeder Technical Loss for the Billing Period shall be the sum of the
hourly Load Losses and No-Load Losses in all medium-voltage
distribution equipment, devices and conductors, excluding the hourly Load
Losses and No-Load Losses in the Sub-Transmission System and
Distribution Substations (which are already accounted for under Section
2.4). It shall be calculated based on Three-Phase Load Flow simulations of
the Distribution System using the appropriate distribution network models
and distribution load models. The Load Flow simulations must capture the
Technical Loss from the metering point associated with the root branch of
the medium-voltage distribution feeders to the connection points of the
Users and loads covered under Distribution Utility Use.
In equation form, the Feeder Technical Loss shall be computed as follows:
Equation A.4. Feeder Technical Loss
∑
∑
∑
∑
∑
∑
∑
∑
∑
∑
∑
A.3.6 Metering Equipment Loss
The Technical Loss associated with Metering Equipment shall be the
electric energy dissipated in the burdens of the Metering Equipment and
Instrument Transformers. The Distribution Utility shall separate the
Metering Equipment based on its location (that is, whether the metering
equipment is connected to (1) the sub-transmission network or the
substation or (2) to the primary or secondary distribution network). In the
calculation of Distribution System Losses, the Distribution Utility shall
ensure that each Metering Equipment is accounted for only once. It shall
be estimated using the following equations, where the subscripts may
denote brand, model, and/or type of each of the components:
24 | P a g e
Equations A.5. Metering Equipment Loss
∑
∑
∑
∑
The Metering Equipment Loss for customers connected through the subtransmission network of the Distribution Utility shall be considered in the
Sub-transmission Technical Loss, while the Metering Equipment Loss for
customers connected through the primary and secondary distribution
networks of the Distribution Utility shall be considered in the Feeder
Technical Loss.
The Distribution Utility shall conduct electrical tests to determine the
power loss in kW of the Instrument Transformers and Electric Meters. In
the absence of exact values, the number of operating hours may be
estimated as the difference between the number of hours in the Billing
Period and the System Average Interruption Duration Index (SAIDI) in
hours in the same Billing Period.
A.3.7 Non-Technical Loss
The Non-Technical Loss shall be the residual loss calculated as the Total
Distribution System Loss less the total Technical Loss for the Billing
Period. The total Technical Loss shall be calculated as the sum of the SubTransmission and Substation Technical Loss and the Feeder Technical
Loss.
25 | P a g e
In equation form, the Non-Technical Loss shall be computed as follows:
Equations A.6 Non-Technical Loss
A.4
Distribution Network Models
For the purpose of calculating the Technical Loss, the Distribution System shall
be represented by distribution network models that are appropriate for threephase load flow simulations. All equipment, devices, and conductors of the
Distribution System shall be characterized to capture the unbalances due to
equipment construction, installation configurations, and connections and due to
unbalanced loading. In addition, the models must capture the Load Losses and
No-Load Losses of Distribution System equipment, devices and conductors,
except Metering Equipment (which are estimated separately).
The Distribution System shall be modeled by an interconnected network of
elements. Each element is represented by series and shunt impedances (or
admittances) using a common node as reference, as illustrated in Figure A-1.
Self- and mutual impedances (or admittances) of each Distribution System
element, such as lines and transformers, shall be included.
Figure A-1. Distribution Network Element Model
A.4.1 Line Models
Overhead sub-transmission lines and overhead primary distribution lines
shall be represented by a three-phase pi (π) equivalent network with the
corresponding self- and mutual impedances of the phase and ground
conductors, as shown in Figure A-2.
26 | P a g e
Figure A-2. Equivalent π-Network of Distribution Lines
The series self- and mutual impedances of the conductors are given by the
Carson equations:
Where,
=
=
=
=
=
Self-impedance of the conductor, in ohms per meter;
Mutual impedance of the conductor, in ohms per meter;
Constant factor for inductance, equal to
ohms per meter;
Resistance of the conductor, in ohms per meter;
Resistance of the earth (a function of frequency), in ohms per
meter;
=
Empirical constant equal to
=
Geometric mean radius (GMR) of the conductor, in feet; and
Distance between conductors x and y (xy can be ab, bc, or ca), in
feet.
=
) feet;
√(
The shunt parameters consist of self- and mutual capacitive reactance due
to the voltages (potentials) across and electrical charges of the conductors
and their mirror images below the ground, as illustrated in Figure A-3.
These parameters can be obtained using the following equations:
[
Where,
27 | P a g e
]
[
][
]
=
=
=
=
=
Distance of conductor x to its image;
Distance of conductor x to the image of conductor y;
Radius of conductor x;
Distance between conductors x and y (xy can be ab, bc, or ca);
and
Permittivity of the region surrounding the conductors.
If conductor w represents the overhead ground wire or grounded neutral
wire, then
, and the coefficient matrix (the [P] matrix) in Eq. 8 can
be reduced using Kron reduction technique to eliminate the row and
column corresponding to conductor w. The resulting matrix equation can
then be inverted to obtain the self- and mutual capacitance of the lines, as
follows:
[
]
[
][
]
Figure A-3. Conductors and their Mirror Images
The admittance parameter Y can be obtained from the inverse of the
capacitive reactance XC, which can be obtained using the following
equation:
Where,
ω = angular frequency in radians per second; and
f = frequency in cycles per second.
Underground and submarine cables shall be modeled using the self- and
mutual impedance and admittances, taking into account the characteristics
of the phase and neutrals conductor, the geometry and spacing of the
conductors inside the cable, the type of cable (for example, if the cable is of
concentric neutral or tape-shielded type), and the parameters of the
material used inside the cables.
28 | P a g e
Secondary Distribution Lines and Service Drops may be modeled similarly,
but the shunt capacitances and mutual reactances for these may be
neglected.
A.4.2 Transformer Models
Substation Transformers, Distribution Transformers, and Voltage
Regulators shall be modeled based on the structure of the magnetic circuit
and the connections of the windings. The leakage impedance (series
impedance) and the magnetizing admittance (shunt admittance) shall
capture the self- and mutual impedance or admittance parameters of the
windings of the transformer or the voltage regulator.
A.4.3 Capacitors and Inductors
Shunt capacitors shall be modeled as either constant resistance and
reactance or constant real and reactive demand that is connected to a bus,
as illustrated in Figure A-4. The real component of the power represents
the No-Load Losses in the capacitors while the reactive power into the bus
is required for power quality improvement.
Figure A-4. Shunt Capacitor Model
Shunt inductors shall be modeled as impedance (a resistance and a
reactance in series) that is connected to a bus, as illustrated in Figure A-5.
The inherent resistance of the shunt inductor shall account for the losses
in the shunt inductor.
Figure A-5. Shunt Inductor Model
29 | P a g e
Series inductors shall be modeled as series impedance that is connected
across two buses, similar to distribution lines, neglecting the shunt
admittances and mutual reactances, as illustrated in Figure A-6. The
inherent resistance of the series inductor shall account for the losses in the
series inductor.
Figure A-6. Series Inductor Model
A.5
Distribution Load Models
Typical Load Curves for different types of customers and customer monthly
energy billing are the basic inputs to the Load Models. The total energy
consumed by each customer is convolved with the normalized load curve
according to the type of customer to determine the hourly real and reactive power
demands, as illustrated in Figure A-7. The power factor of each customer is
specified based on measurements or reasonable assumptions.
Figure A-7. Developing the Load Models
30 | P a g e
Figure A-8 shows the step-by-step procedure for converting energy consumption
(expressed in kWh for one billing period) to 24 hourly kW demands. The real
power demand Pt for time t is obtained from the per unit (p.u.) demand pt
divided by the total area under the normalized load curve.
Figure A-8. Converting Monthly Customer Energy Bill to Hourly Power Demand
The power factor (pft) is used to compute for the hourly reactive power demand
(Qt) based on the real power demand of the corresponding hour.
The real power and reactive power may be divided into three components to
represent constant power, constant current, and constant impedance load models
if their coefficients are known. For the purpose of segregating Distribution
System Loss, constant power load models (that is, constant P and Q) shall be
acceptable.
Figure A-9 shows the shows an example of the hourly real and reactive power
demands for a customer.
Figure A.9. Example of the Hourly Power Demand of a Customer
31 | P a g e
The Distribution Utility may develop more accurate load models by preparing as
many load curves as possible through a load survey for each type of customer,
and even for each sub-type of customer. Different load curves may also consider
seasonal variations (for example: dry and wet season) and variations based on
types of the day (for example: weekday, weekend, and/or holidays).
A.6
Data Requirements
This section specifies the data required to segregate Distribution System
Losses into Technical Loss and Non-Technical Loss and establish caps on the
Recoverable Rate of Distribution System Losses. These data shall be
submitted to the ERC using the Data Requirements Templates in Annex C.
Data shall be organized and submitted to the ERC so that the entire
distribution system covered by each set of incoming metering point(s) can
be simulated (e.g., per substation).
A.6.1 Distribution Utility Load Data
For the Distribution Utility Use, the Distribution Utility shall submit to
ERC for approval, the list of actual connected and essential loads
shown in Table 1. These are required to establish the allowances for
Distribution Utility U s e hat can be passed on to customers. These
data shall be submitted using the template ERC-DSLCAP-08 which
shall be signed by the Responsible Person of the Distribution Utility.
Table 1. Distribution Utility Load Data
Distribution Utility Load Type
Name of Facility
Location of Facility
Purpose of Facility
Space Area (sq. m.)
Number of Users/Occupants
Quantity
Connected Load (Description)
Use of Connected Load
Rating (Watts)
Average Demand (kW)
Average Duration (h)
Ave. Monthly Consumption (kWh)
Total Monthly Energy Consumption (kWh)
A.6.2 Data for Distribution Load Models
The data for developing the Distribution Load Models are shown in
Table 2 to Table 5. These are required to determine the hourly power
demands in a billing period that shall be used for the calculation of
Technical Loss. The following templates shall be used in submitting
these data to the ERC:
a)
b)
c)
d)
32 | P a g e
ERC-DSL-02:
ERC-DSL-03:
ERC-DSL-04:
ERC-DSL-05:
Customer Data;
Billing Cycle Data;
Customer Energy Consumption Data; and
Load Curve Data.
Table 2. Customer Data
Customer ID
Customer Name
Customer Type
Service Voltage
No. of Phase(s)
Table 3. Billing Cycle Data
Billing Period Code
Period Covered of the Billing Cycle
Number of Days for the Billing Period
Number of Hours for the Billing Period
Table 4. Customer Energy Consumption Data
Customer ID
Billing Period Code
Energy Consumed (kWh) by the Customer for the Billing Period
Measured or Estimated Power Factor
Table 5. Load Curve Data
Customer Type
Description of the Customer Type
Per Unit Load of each Customer Type for Hour 1 to Hour 24
A.6.3 Data for Distribution Network Models
The following Distribution System data are required for developing
Distribution Network Models for the Three-Phase Load Flow
simulations:
a)
b)
c)
d)
e)
f)
g)
h)
i)
j)
k)
Bus Data;
Sub-Transmission Line Data;
Substation Power Transformer Data;
Primary Distribution Line Data;
Distribution Transformer Data;
Secondary Distribution Line Data;
Primary and Secondary Customer Service Drop Data;
Voltage Regulator Data;
Shunt Capacitor Data;
Shunt Inductor Data; and
Series Inductor Data.
The details of these Distribution System data are specified in Table 6 to
Table 21 and shall be submitted to the ERC using Templates found in
Annex C of this Rules.
Table 6. Bus Data
Identification of Connection Points (Bus ID)
Bus Description (e.g., Location of the Connection Point)
Nominal Voltage of the Connection Point
Note: Connection point refers to a delivery point or a point connecting two
ormore distribution system element
33 | P a g e
Table 7. Sub-Transmission Line Data – Overhead
Subtransmission Line Segment ID
Connection Points Identification (From Bus ID and To Bus ID)
Phasing
Configuration
No. of Ground Wires
Length of Subtransmission Line Segment
Phase Conductor Type
Size of Phase Conductors
No. of Strands of Phase Conductors
No. of Bundled Conductors
Bundled Conductors Spacing
Conductor Type of Ground Wire
Size of Ground Wire
No. of Strands of Ground Wire
Spacing between phase conductors
Spacing between phase conductors and ground wire
Spacing between ground wires (meters)
Spacing between circuits for parallel/double circuits
Height of Phase Conductors
Height of Ground Wire
Earth Resistivity
Table 8. Subtransmission Line Data - Underground/Submarine
Subtransmission Line Segment ID
Connection Points Identification (From Bus ID and To Bus ID)
Phasing
Length of Subtransmission Line Segment
Conductor Type
Conductor Size
No. of Cores
Diameter under Armor
Armor Wire Diameter (mm)
Overall Diameter (mm)
AC Resistance (ohm/km)
Inductive Reactance (Ohm/km)
Capacitance (Micro-farad/km)
Earth Resistivity (ohm-meter)
Table 9. Substation Power Transformer Data – Two Winding
Substation Power Transformer ID
Connection Points Identification
Core
Structure
(Primary
Bus ID and Secondary Bus ID)
Method of Cooling
Power Rating (Normal and Maximum)
Voltage Rating of Primary and Secondary Windings
Connection of Primary and Secondary Windings
Grounding Connection of Primary and Secondary Windings
Tap Changer Type
Winding w/ Auto LTC
Tap Settings
Impedance (%Z)
X/R Ratio
No-Load Loss (kW)
Exciting Current (%)
34 | P a g e
Table 10. Substation Power Transformer Data - Three Winding
Substation Power Transformer ID
Connection Points Identification
(Primary
Bus ID, Secondary Bus ID and Tertiary Bus ID)
Core
Structure
Method of Cooling
Power Rating (Normal and Maximum)
Voltage Rating of Primary, Secondary and Tertiary Windings
Connection of Primary, Secondary and Tertiary Windings
Grounding Connection of Primary, Secondary and Tertiary
Tap Changer Type
Windings
Winding w/ Auto LTC
Tap Settings
Impedance (%Zps, %Zpt, %Zst)
X/R Ratio (X/Rps, X/Rpt, X/Rst)
No-Load Loss
Exciting Current
Table 11. Primary Distribution Line Data – Overhead
Primary Distribution Line Segment ID
Connection Points Identification (From Bus ID and To Bus ID)
Phasing
Configuration
System Grounding Type (Uni- or Mult-grounded)
Length of Primary Distribution Line Segment
Phase Conductor Type
Size of Phase Conductors
No. of Strands of Phase Conductors
Conductor Type of Neutral Wire
Size of Neutral Wire
No. of Strands of Neutral Wire
Spacing between Phase Conductors
Spacing between Phase Conductors and Neutral Wire
Spacing between Circuits for Parallel/Double Circuits
Height of Phase Conductors
Height of Neutral Wire
Earth Resistivity
Table 12. Primary Distribution Line Data - Underground
Primary Distribution Line Segment ID
Connection Points Identification (From Bus ID and To Bus ID)
Phasing
Length of Primary Distribution Line Segment
Conductor Type
Conductor Size
No. of Cores
Diameter under Armor
Armor Wire Diameter
Overall Diameter
AC Resistance
Inductive Reactance
Capacitance
Earth Resistivity
Table 13. Primary Customer Service Drop Data – Overhead
Primary Customer Service Drop ID
Connection Points Identification (From Bus ID and To Bus ID)
Phasing
Configuration
System Grounding Type (Uni- or Multi-grounded)
Length of Service Drop
Phase Conductor Type
35 | P a g e
Size of Phase Conductors
No. of Strands of Phase Conductors
Conductor Type of Neutral Wire
Size of Neutral Wire
No. of Strands of Neutral Wire
Spacing between phase conductors
Spacing between phase conductors and Neutral Wire
Spacing between Circuits for Parallel/Double Circuits
Height of Phase Conductors
Height of Neutral Wire
Earth Resistivity
Table 14 Primary Customer Service Drop Data - Underground
Primary Customer Service Drop ID
Connection Points Identification (From Bus ID and To Bus ID)
Phasing
Length of Service Drop
Conductor Type
Conductor Size
No. of Cores
Diameter under Armor
Armor Wire Diameter
Overall Diameter
AC Resistance
Inductive Reactance
Capacitance
Earth Resistivity
Table 15. Distribution Transformer Data
Distribution Transformer ID
Connection Points Identification
Phasing
(Primary Bus ID and Secondary Bus ID)
Installation Type
No. of Distribution Transformers in a Bank
Connection of Windings
Power Rating
Voltage Rating of Primary and Secondary Winding
Tap Settings
Impedance
X/R Ratio
No-Load Loss
Exciting Current
Table 16. Secondary Distribution Line Data
Secondary Distribution Line ID
Connection Points Identification (From Bus ID and To Bus ID)
Phasing
Installation Type
Length of Secondary Distribution Line Segment
Conductor Type
Conductor Size
Table 17. Secondary Customer Service Drop Data
Secondary Customer Service Drop ID
Connection Points Identification (From Bus ID and To Bus ID)
Phasing
Installation Type
Service Drop Segment Length before the Metering Equipment
Service Drop Segment Length after the Metering Equipment
Conductor Type
Conductor Size
36 | P a g e
Table 18. Voltage Regulator Data
Voltage Regulator ID
Connection Points Identification (From Bus ID and To Bus ID)
Regulated Bus ID
Phase Type
Phasing
Location of Voltage Sensor (Phase Sense)
Power Rating
Voltage Rating
Target Voltage Computed at 120V base
Bandwidth of Voltage Regulation at 120V base
R- and X-Settings
Primary Current Rating
Potential Transformer (PT) Ratio
No-Load Loss
Exciting Current
Table 19. Shunt Capacitor Data
Shunt Capacitor ID
Connection Point Identification (Bus ID)
Phase Type
Phasing
Voltage Rating
Reactive Power Rating
Power Loss
Table 20. Shunt Inductor Data
Shunt Inductor ID
Connection Point Identification (Bus ID)
Phase Type
Phasing
Voltage Rating
Resistance
Reactance
Table 21. Series Inductor Data
Series Inductor ID
Connection Points Identification (From Bus ID and To Bus ID)
Phase Type
Phasing
Voltage Rating
Resistance
Reactance
37 | P a g e
ANNEX B: Reportorial Requirement Guidelines
To achieve uniformity and consistency in data submission and evaluation, the
Distribution Utility shall annually submit the following data using the conventions and
format described in Sections B.1-B.3.
B.1
Monthly Sub-Transmission and Substation DSL Data
The Distribution Utility shall submit the monthly sub-transmission network and
distribution substations DSL data in the format described in the following
templates:
a) ERC-DSLSUBT-00: DSL-SUBT Simulation Parameters Data
b) ERC-DSLSUBT-01: Billing Cycle Data
c) ERC-DSLSUBT-02: Metered Input Energy
d) ERC-DSLSUBT-03: Load Data
e) ERC-DSLSUBT-04: Load Energy Consumption Data
f) ERC-DSLSUBT-05: Load Curve Data
g) ERC-DSLSUBT-06: Bus Data
h) ERC-DSLSUBT-07: Subtransmission Line-Overhead
i) ERC-DSLSUBT-08: Subtransmission Line-Underground
j) ERC-DSLSUBT-09: Power Transformer-2 Winding
k) ERC-DSLSUBT-10: Power Transformer-3 Winding
l) ERC-DSLSUBT-11: Subtrans Svc Drop-Overhead
m) ERC-DSLSUBT-12: Subtrans Svc Drop-Underground
n) ERC-DSLSUBT-13: Voltage Regulator Data
o) ERC-DSLSUBT-14: Shunt Capacitor Data
p) ERC-DSLSUBT-15: Shunt Inductor Data
q) ERC-DSLSUBT-16: Series Inductor Data
ERC-DSLSUBT-00:
DSL-SUBT Simulation Parameters
This data describe the parameters that will be used in the simulation of DSL for the Subtransmission Network and Distribution Substation data.
Sub-Transmission Root Bus ID
Specify the Bus ID of the root connection point for the Sub-transmission Network. This
ID must be found in the Bus Data sheet.
Sub-Transmission Energy Input (kWh)
Specify the energy input in kWh for the Sub-transmission Network for a particular
Billing Cycle. This is the energy that was purchased by the DU for the Sub-transmission
Network for the given billing period.
DU Use (kWh)
Specify the energy in kWh used by the DU for its operation for the Sub-transmission
Network for a particular Billing Cycle.
38 | P a g e
Power Mismatch
Specify the Power Mismatch that will be used as convergence criteria for the load flow
simulation. Once the computed power mismatch value is less than the specified value,
the load flow simulation considers the solution as convergent (or has arrived at a fixed
value), otherwise, the process will continue to iterate until power mismatch is less than
the specified value or until the process has reached the specified Maximum Iteration.
(Typical value for Power Mismatch is 0.00001)
Base kVA
Specify the Base kVA that will be used in converting the network models to per unit. This
process is done before the actual load flow simulation process. (Typical value for Base
kVA is 15)
Maximum Iteration
Specify the Maximum Iteration that will be used as stopping criteria for the load flow
simulation. For each iteration of the load flow process, the computed power mismatch is
compared to the specified Power Mismatch. When the computed power mismatch value
is greater than the specified Power Mismatch, the load flow process continues to iterate.
The Maximum Iteration field will serve to stop the simulation if it has reached the
maximum number of iteration regardless if the simulation has reached a convergent
solution or not. (Typical value for Maximum Iteration is 50)
Percent PQ
Specify the Percent PQ that will be used for the modeling of the loads or customers for
the given data. Percent PQ signifies the percentage of all loads or customers that are
considered or behave as constant power loads. (Typical value for Percent PQ is 100)
Percent Z
Specify the Percent Z that will be used for the modeling of the loads or customers for the
given data. Percent Z signifies the percentage of all loads or customers that are
considered or behave as constant impedance loads. (Typical value for Percent Z is 0)
Percent Loading
Specify the Percent Loading that will be used for the aggregate scaling of all the
connected loads or customers for the given data. A Percent Loading value of 90 signifies
that all the customer loads are scaled by 90%. (Typical value for Percent Loading is 100)
Source Voltage Hour 1-24
Specify the hourly voltage profile in per unit at the Source or Root Bus of the Subtransmission Network. (Typical value for Source Voltage per hour is 1.0)
39 | P a g e
ERC-DSLSUBT-01:
Billing Cycle Data
Billing Period Code
Specify the Billing Period according to the following coding system:
YYYYMM
Where YYYY – Year of the meter reading period (e.g. 2017 for year 2017)
MM – Month of the meter reading period (e.g. 08 for August)
Period Covered
Specify the month, day, and year covered by the Billing Cycle.
Number of Days
Specify the number of days covered by the Billing Period.
Number of Hours
Specify the total number of hours covered by the Billing Period.
ERC-DSLSUBT-02:
Metered Input Energy
Meter ID
Specify the unique ID for the meter using up to 25 alphanumeric characters along with
dash (-) and underscore (_).
From Bus ID
Specify the Bus ID of the sending end of the meter connection point. This Bus ID must
correspond to that specified in the Bus Data.
To Bus ID
Specify the Bus ID of the receiving end of the meter connection point. This Bus ID must
correspond to that specified in the Bus Data.
Metering Point Description
Specify the description of the metering point (e.g. location).
Metered Input (kWh)
Specify the value in kWh for the specific feeder for the given Billing Period. This value is
based on the actual meter reading from the meters.
ERC-DSLSUBT-03:
Load Data
Load ID
Specify the unique ID that will identify a load (e.g. specific feeder). All loads connected to
the Sub-Transmission Network must be included in this list.
Load Name
Specify the name of the Load that corresponds to the Load ID.
Load Type
Specify the type or classification of load using up to 25 alphanumeric characters (e.g.
FDR1 for feeder1, FDR2 for feeder2, etc.). All Load Types used in this list must be
defined in the Load Curve Data.
40 | P a g e
Service Voltage
Specify the nominal service voltage being supplied to the load in kV (e.g. 13.2).
Phase
Specify the number of phase(s) of the load service.
1 – Single-Phase, or
3 – Three-Phase
ERC-DSLSUBT-04:
Load Energy Consumption Data
Load ID
Specify the unique ID that identifies a load. This must be the same ID used in the Load
Data.
Billing Period Code
Specify the Billing Period according to the following coding system:
YYYYMM
Where YYYY – Year of the meter reading period (e.g. 2017 for year 2017)
MM – Month of the meter reading period (e.g. 08 for August)
Energy Consumed (kWh)
Specify the energy consumption in kWh of the load for the Billing Period (e.g. meter
reading for a specific feeder).
Power Factor
Specify the average power factor (measured or estimated) of the load for the Billing
Period.
ERC-DSLSUBT-05:
Load Curve Data
Load Curve ID
Specify the unique ID of the load curve for the Load Type.
Load Type
Specify the type or classification of the load represented by the load curve. This must be
corresponding to the Load Type specified in the Load Data.
Description
Specify the description of the Load Type.
Hour 1 to Hour 24
Specify the normalized hourly demand from Hour 1 to Hour 24 of the Load Curve in per
unit. This can be obtained by monitoring the 24-hour demand pattern of the Load Type
(e.g. hourly Ampere, kW, kVA, etc.). To obtain the normalized demand in per unit, each
hourly demand is divided by the peak demand. Thus, the highest value of the normalized
hourly demand is 1.0 which coincides with the peak hour.
41 | P a g e
ERC-DSLSUBT-06:
Bus Data
Bus ID
Specify the unique ID of the Bus or Node in the Sub-Transmission System using up to 25
alphanumeric characters. Bus or node is created for each connection or junction point
from the Sub-Transmission Lines to the Substation Power Transformers.
Description
Specify the description of the Bus or Node.
Nominal Voltage (kV)
Specify the nominal voltage of the Bus or Node in kV (e.g. 69, 13.2).
ERC-DSLSUBT-07:
Subtransmission Line-Overhead
Each Sub-Transmission Line segment must be included as one data entry. The whole
length of the Sub-Transmission Line may be entered as one or more line segments
depending on the connection points and the construction arrangements.
Sub-Transmission Line Segment ID
Specify the unique ID of the Sub-Transmission Line segment using up to 25
alphanumeric characters.
From Bus ID
Specify the Bus ID of the sending end of the Sub-Transmission Line segment. This Bus
ID must correspond to that specified in the Bus Data.
To Bus ID
Specify the Bus ID of the receiving end of the Sub-Transmission Line segment. This Bus
ID must correspond to that specified in the Bus Data.
Phasing
Specify the phase arrangement of the Sub-Transmission Line segment.
ABC, ACB, BCA, BAC, CAB, or CBA.
In specifying the Phasing, conductor 1 shall be assumed to be always in the leftmost side
when facing the secondary side of the Substation Power Transformer for triangular and
horizontal configuration or the highest conductor in the case of vertical configuration as
illustrated in Figure 3.
Figure 3. Conductor Arrangement
42 | P a g e
Configuration
Specify the installation configuration of the conductors of the Sub-Transmission Line
segment. The values are defined by the following:
Triangular;
Horizontal;
Vertical; or
Parallel (for Double Circuit).
No. of Ground Wires
Specify the number of ground wires. The values are defined by the following:
1 – for one ground wire; or
2 – for two ground wires.
Length (meters)
Specify the length of the Sub-Transmission Line segment in meters.
Conductor Type
Specify the material type of the phase conductor. The values are defined by the following
list (not limited to):
ACSR – for Aluminum Cable Steel Reinforced;
AL – for All Aluminum Conductor; and
CU – for Copper Conductor.
Conductor Size and Unit (C)
Specify the size of the phase conductor. The values are defined by the following list (not
limited to):
AWG;
CM; or
mm2.
Strands (C)
Specify the number of strands of the phase conductor. For ACSR, the number of strands
of the aluminum and steel shall be specified according to the following format:
Al/St
For example, an ACSR with 6 Aluminum strands and 1 Steel should have “6/1” entry in
the Strands field.
Bundled Conductors
Specify the number of bundled conductors of the phase conductor. The values are
defined by the following list:
1 – for Single Conductor
2 – for Two-Conductor Bundle
3 – for Three-Conductor Bundle
4 – for Four-Conductor Bundle
43 | P a g e
Bundled Cond. Spacing (cm)
Specify the spacing S of bundled conductors in centimeters (see Figure 4). Specify a value
of “0.0” for Single Conductor.
Figure 4. Bundling of Conductors
Ground Wire Type
Specify the type of material of the Ground Wire. The values are defined by the following
list (not limited to):
ACSR – for Aluminum Cable Steel Reinforced;
AL – for Aluminum Conductor;
CU – for Copper Conductor; and
ST – for Steel Wire.
Ground Wire Size and Unit (GW)
Specify the size of the Ground Wire. The values are defined by the following list (not
limited to):
AWG;
CM; or
mm2.
Strands (GW)
Specify the number of strands of the Ground Wire. For ACSR, the number of strands of
the aluminum and steel shall be specified according to the following format:
Al/St
For example, an ACSR with 6 Aluminum strands and 1 Steel should have “6/1” entry in
the Strands field.
Spacing D12 (meters)
Specify the distance in meters between Conductor 1 and Conductor 2. See Figure 5.
Spacing D23 (meters)
Specify the distance in meters between Conductor 2 and Conductor 3. See Figure 5.
Spacing D13 (meters)
Specify the distance in meters between Conductor 1 and Conductor 3. See Figure 5.
44 | P a g e
Figure 5. Conductor Spacing
Spacing D1g (meters)
Specify the distance in meters between Conductor 1 and the Ground Wire. For SubTransmission Line with two Ground Wires, the distance of Conductor 1 to the leftmost
Ground Wire shall be specified. See Figure 6.
Spacing D2g (meters)
Specify the distance in meters between Conductor 2 and the Ground Wire. For SubTransmission Line with two Ground Wires, the distance of Conductor 2 to the center of
the two Ground Wires shall be specified. See Figure 6.
Spacing D3g (meters)
Specify the distance in meters between Conductor 3 and the Ground Wire. For SubTransmission Line with two Ground Wires, the distance of Conductor 3 to the rightmost
Ground Wire shall be specified. See Figure 6.
Figure 6. Spacing of Phase Conductors and Ground Wire
Spacing Dgg (meters)
Specify the distance in meters between the two Ground Wires. See Figure 7.
Figure 7. Distance between Ground Wires
45 | P a g e
Spacing Dc1-c2 (meters)
For parallel configuration (double circuit), specify the distance in meters between the
nearest phase conductors of Circuit 1 and Circuit 2. See Figure 8.
Figure 8. Distance between Circuit 1 and Circuit 2
Height H1 (meters)
Specify the height in meters of Conductor 1 of the Sub-Transmission Line segment.
Specify the value “0.0” if not applicable. See Figure 9.
Height H2 (meters)
Specify the height in meters of Conductor 2 of the Sub-Transmission Line segment.
Specify the value “0.0” if not applicable. See Figure 9.
Height H3 (meters)
Specify the height in meters of Conductor 3 of the Sub-Transmission Line segment.
Specify the value “0.0” if not applicable. See Figure 9.
Height Hg (meters)
Specify the height in meters of the Ground Wire of the Sub-Transmission Line segment.
Specify the value “0.0” if not applicable. See Figure 9.
Figure 9. Height of Phase Conductors and Ground Wires
Earth Resistivity (Ohm-meter)
Specify the earth resistivity in ohm-meter. Use a value of 100 for average damp earth if
the value of resistivity is not known.
46 | P a g e
ERC-DSLSUBT-08:
Subtransmission Line-Underground
Sub-Transmission Line Segment ID
Specify the unique ID of the Sub-Transmission Line segment using up to 25
alphanumeric characters.
From Bus ID
Specify the unique ID of the sending end of the Sub-Transmission Line segment. This
Bus ID must correspond to that specified in the Bus Data.
To Bus ID
Specify the unique ID of the receiving end of the Sub-Transmission Line segment. This
Bus ID must correspond to that specified in the Bus Data.
Phasing
Specify the phase arrangement of the Sub-Transmission Line segment.
ABC, ACB, BCA, BAC, CAB, or CBA.
In specifying the Phasing, conductor 1 shall be assumed to be always in the leftmost side
when facing the secondary side of the Substation Power Transformer for triangular and
horizontal configuration or the highest conductor in the case of vertical configuration as
illustrated in Figure 3.
Length (meters)
Specify the length of the Sub-Transmission Line segment in meters.
Conductor Type
Specify the material type of the phase conductor. The values are defined by the following
list (not limited to):
AL – for All Aluminum Conductor; and
CU – for Copper Conductor.
Conductor Size and Unit (C)
Specify the size of the phase conductor. The values are defined by the following list (not
limited to):
AWG;
CM; or
mm2.
No. of Cores (C)
Specify the number of cores of the cable. The values are defined by the following:
1 – Single-Core Cable;
2 – Two-Core Cable;
3 – Three-Core Cable; and
4 – Four-Core Cable.
Diameter under Armor (mm)
Specify the diameter under the Armor Wire in millimeters. See Figure 10.
47 | P a g e
Armor Wire Diameter (mm)
Specify the diameter of the Armor Wire in millimeters. See Figure 10.
Overall Diameter (mm)
Specify the overall diameter of the cable in millimeters. See Figure 10.
Figure 10. Constructional Data of Underground Cable
AC Resistance (ohm/km)
Specify the AC resistance of the conductor in ohm/km.
Inductive Reactance (ohm/km)
Specify the inductive reactance of the cable in ohm/km.
Capacitance (micro-farad/km)
Specify the star capacitance of the cable in micro-farad/km.
Earth Resistivity (ohm-meter)
Specify the earth resistivity in ohm-meter. Use a value of 100 for average damp earth if
the value of resistivity is not known.
ERC-DSLSUBT-09:
Power Transformer-2 Winding
Substation Power Transformer ID
Specify the unique ID of the Substation Power Transformer using up to 25 alphanumeric
characters.
From Primary Bus ID
Specify the Bus ID where the primary of the Substation Power Transformer is connected.
This Bus ID must correspond to that specified in the Bus Data.
To Secondary Bus ID
Specify the Bus ID where the secondary of the Substation Power Transformer is
connected. This Bus ID must correspond to that specified in the Bus Data.
Core Structure
Specify the Core Structure of the Substation Power Transformer. The values are defined
by the following list:
1 – if not known;
2 – for Shell Type Transformer;
3 – for 3-legged Core Type Transformer;
4 – for 4-legged Core Type Transformer; and
5 – for 5-legged Core Type Transformer.
48 | P a g e
Method of Cooling
Specify the method of cooling of the Substation Power Transformer. The values are
defined by the following list (not limited to):
OA; and
OA/FA.
kVA Rating (Primary)
Specify the rated capacity in kVA of the primary winding of the Substation Power
Transformer.
kVA Rating (Secondary)
Specify the rated capacity in kVA of the secondary winding of the Substation Power
Transformer.
Max kVA (Primary)
Specify the maximum capacity in kVA of the primary winding of the Substation Power
Transformer where the transformer has forced cooling system.
Max kVA (Secondary)
Specify the maximum capacity in kVA of the secondary winding of the Substation Power
Transformer where the transformer has forced cooling system.
kV Rating (Primary)
Specify the voltage rating in kV of the primary winding of the Substation Power
Transformer.
kV Rating (Secondary)
Specify the voltage rating in kV of the secondary winding of the Substation Power
Transformer.
Connection (Primary)
Specify the primary winding connection of the Substation Power Transformer (values are
either DELTA or WYE).
Connection (Secondary)
Specify the secondary winding connection of the Substation Power Transformer (values
are either DELTA or WYE).
Grounding (Primary)
Specify the grounding connection of the Substation Power Transformer at the primary
side. The values are defined by the following:
0 – Ungrounded
1 – Solidly Grounded
2 – Low Resistance Grounded
3 – High Resistance Grounded
4 – Reactance Grounded
49 | P a g e
Grounding (Secondary)
Specify the grounding connection of the Substation Power Transformer at the secondary
side. The values are defined by the following:
0 – Ungrounded
1 – Solidly Grounded
2 – Low Resistance Grounded
3 – High Resistance Grounded
4 – Reactance Grounded
Tap Changer Type
Specify the type of Tap Changer of the Substation Power Transformer. The values are
defined by the following:
Fixed – for Off-Load, Manual On-Load, and No Tap Changer
Automatic – for Automatic Load Tap Changer
Winding with Auto LTC
Specify the winding where Automatic Load Tap Changing operation takes place. The
values are defined by the following:
PRI – for primary winding;
SEC – for secondary winding;
TER – for tertiary winding;
NA – for if not applicable.
Tap kV Setting (Primary)
Specify the Tap Voltage Setting in kV at the primary side. Specify the rated voltage if not
applicable.
Tap kV Setting (Secondary)
Specify the Tap Voltage Setting in kV at the secondary side. Specify the rated voltage if
not applicable.
Impedance (%Z)
Specify the Percent Impedance (%Z) of the Substation Power Transformer taken from
the nameplate of the transformer. Use typical value if data is not available.
X/R Ratio
Specify the X/R Ratio of the Substation Power Transformer taken from the nameplate of
the transformer. Use typical value if data is not available.
No-Load Loss (kW)
Specify the No-Load loss in kW of the Substation Power Transformer taken from the
nameplate of the transformer. Use typical value if data is not available.
Exciting Current (%)
Specify the Exciting Current of the Substation Power Transformer in percent of the rated
current taken from the nameplate of the transformer. Use typical value if data is not
available.
50 | P a g e
ERC-DSLSUBT-10:
Power Transformer-3 Winding
Substation Power Transformer ID
Specify the unique ID of the Substation Power Transformer using up to 25 alphanumeric
characters.
From Primary Bus ID
Specify the Bus ID where the primary of the Substation Power Transformer is connected.
This Bus ID must correspond to that specified in the Bus Data.
To Secondary Bus ID
Specify the Bus ID where the secondary of the Substation Power Transformer is
connected. This Bus ID must correspond to that specified in the Bus Data.
To Tertiary Bus ID
Specify the Bus ID where the tertiary of the Substation Power Transformer is connected.
This Bus ID must correspond to that specified in the Bus Data.
Core Structure
Specify the Core Structure of the Substation Power Transformer. The values are defined
by the following list:
1 – if not known;
2 – for Shell Type Transformer;
3 – for 3-legged Core Type Transformer;
4 – for 4-legged Core Type Transformer;
5 – for 5-legged Core Type Transformer.
Method of Cooling
Specify the method of cooling of the Substation Power Transformer. The values are
defined by the following list (not limited to):
OA; and
OA/FA.
kVA Rating (Primary)
Specify the rated capacity in kVA of the primary winding of the Substation Power
Transformer.
kVA Rating (Secondary)
Specify the rated capacity in kVA of the secondary winding of the Substation Power
Transformer.
kVA Rating (Tertiary)
Specify the rated capacity in kVA of the tertiary winding of the Substation Power
Transformer.
Max kVA (Primary)
Specify the maximum capacity in kVA of the primary winding of the Substation Power
Transformer where the transformer has forced cooling system.
Max kVA (Secondary)
Specify the maximum capacity in kVA of the secondary winding of the Substation Power
Transformer where the transformer has forced cooling system.
51 | P a g e
Max kVA (Tertiary)
Specify the maximum capacity in kVA of the tertiary winding of the Substation Power
Transformer where the transformer has forced cooling system.
kV Rating (Primary)
Specify the voltage rating in kV of the primary winding of the Substation Power
Transformer.
kV Rating (Secondary)
Specify the voltage rating in kV of the secondary winding of the Substation Power
Transformer.
kV Rating (Tertiary)
Specify the voltage rating in kV of the tertiary winding of the Substation Power
Transformer.
Connection (Primary)
Specify the primary winding connection of the Substation Power Transformer (values are
either DELTA or WYE).
Connection (Secondary)
Specify the secondary winding connection of the Substation Power Transformer (values
are either DELTA or WYE).
Connection (Tertiary)
Specify the tertiary winding connection of the Substation Power Transformer (values are
either DELTA or WYE).
Grounding (Primary)
Specify the grounding connection of the Substation Power Transformer at the primary
side. The values are defined by the following:
0 – Ungrounded
1 – Solidly Grounded
2 – Low Resistance Grounded
3 – High Resistance Grounded
4 – Reactance Grounded
Grounding (Secondary)
Specify the grounding connection of the Substation Power Transformer at the secondary
side. The values are defined by the following:
0 – Ungrounded
1 – Solidly Grounded
2 – Low Resistance Grounded
3 – High Resistance Grounded
4 – Reactance Grounded
52 | P a g e
Grounding (Tertiary)
Specify the grounding connection of the Substation Power Transformer at the tertiary
side. The values are defined by the following:
0 – Ungrounded
1 – Solidly Grounded
2 – Low Resistance Grounded
3 – High Resistance Grounded
4 – Reactance Grounded
Tap Changer Type
Specify the type of Tap Changer of the Substation Power Transformer. The values are
defined by the following:
Fixed – for Off-Load, Manual On-Load, and No Tap Changer
Automatic – for Automatic Load Tap Changer
Winding with Auto LTC
Specify the winding where Automatic Load Tap Changing operation takes place. The
values are defined by the following:
PRI – for primary winding;
SEC – for secondary winding;
TER – for tertiary winding;
NA – for if not applicable.
Tap kV Setting (Primary)
Specify the Tap Voltage Setting in kV at the primary side. Specify the rated voltage if not
applicable.
Tap kV Setting (Secondary)
Specify the Tap Voltage Setting in kV at the secondary side. Specify the rated voltage if
not applicable.
Tap kV Setting (Tertiary)
Specify the Tap Voltage Setting in kV at the tertiary side. Specify the rated voltage if not
applicable.
Impedance (%Zps)
Specify the Percent Impedance (%Z) between the primary and secondary windings of the
Substation Power Transformer taken from the nameplate of the transformer. Use typical
value if data is not available.
X/R Ratio (X/Rps)
Specify the X/R Ratio of the Substation Power Transformer impedance between the
primary and secondary windings taken from the nameplate of the transformer. Use
typical value if data is not available.
Impedance (%Zpt)
Specify the Percent Impedance (%Z) between the primary and tertiary windings of the
Substation Power Transformer taken from the nameplate of the transformer. Use typical
value if data is not available.
53 | P a g e
X/R Ratio (X/Rpt)
Specify the X/R Ratio of the Substation Power Transformer impedance between the
primary and tertiary windings taken from the nameplate of the transformer. Use typical
value if data is not available.
Impedance (%Zst)
Specify the Percent Impedance (%Z) between the secondary and tertiary windings of the
Substation Power Transformer taken from the nameplate of the transformer. Use typical
value if data is not available.
X/R Ratio (X/Rst)
Specify the X/R Ratio of the Substation Power Transformer impedance between the
secondary and tertiary windings taken from the nameplate of the transformer. Use
typical value if data is not available.
No-Load Loss (kW)
Specify the No-Load loss in kW of the Substation Power Transformer taken from the
nameplate of the transformer. Use typical value if data is not available.
Exciting Current (%)
Specify the Exciting Current of the Substation Power Transformer in percent of the rated
current taken from the nameplate of the transformer. Use typical value if data is not
available.
ERC-DSLSUBT-11:
Subtrans Svc Drop-Overhead
Each Sub-Transmission Service Drop represents a segment leading to a Load in the SubTransmission Network.
Sub-Transmission Load Service Drop ID
Specify the unique ID of the Sub-Transmission Load Service Drop using up to 25
alphanumeric characters.
From Bus ID
Specify the Bus ID of the sending end of the Sub-Transmission Load Service Drop. This
Bus ID must correspond to that specified in the Bus Data.
To Load ID
Specify the Load ID of the receiving end of the Sub-Transmission Load Service Drop.
This Load ID must correspond to that specified in the Load Data.
Phasing
Specify the phase arrangement of the Sub-Transmission Load Service Drop.
ABC – for Uni-grounded System, or
ABCN – for Multi-grounded System
In specifying the Phasing, conductor 1 shall be assumed to be always in the leftmost side
when facing the secondary side of the Substation Power Transformer for triangular and
horizontal configuration or the highest conductor in the case of vertical configuration as
illustrated in Figure 11.
54 | P a g e
Phasing shall be specified using the following conventions:
a) ABCN or ABC if Phases A, B, and C correspond to conductor 1, 2, and 3
respectively;
b) ACBN or ACB if Phases A, C, and B correspond to conductor 1, 2, and 3
respectively;
c) BCAN or BCA if Phases B, C, and A correspond to conductor 1, 2, and 3
respectively;
d) BACN or BAC if Phases B, A, and C correspond to conductor 1, 2, and 3
respectively;
e) CABN or CAB if Phases C, A, and B correspond to conductor 1, 2, and 3
respectively;
f) CBAN or CBA if Phases C, B, and A correspond to conductor 1, 2, and 3
respectively;
g) ABN or AB if Phases A and B correspond to conductor 1 and 2 respectively;
h) BAN or BA if Phases B and A correspond to conductor 1 and 2 respectively;
i) BCN or BC if Phases B and C correspond to conductor 1 and 2 respectively;
j) CBN or CB if Phases C and B correspond to conductor 1 and 2 respectively;
k) CAN or CA if Phases C and A correspond to conductor 1 and 2 respectively;
l) ACN or AC if Phases A and C correspond to conductor 1 and 2 respectively;
m) AN or A if Phase A corresponds to conductor 1;
n) BN or B if Phase B corresponds to conductor 1; and
o) CN or C if Phase C corresponds to conductor 1.
Configuration
Specify the installation configuration of the conductors of the Sub-Transmission Load
Service Drop. The values are defined by the following:
Triangular;
Horizontal; or
Vertical.
System Grounding Type
Specify the system grounding type. The values are defined by the following:
Uni-grounded; or
Multi-grounded.
Length (meters)
Specify the length of the Sub-Transmission Load Service Drop in meters.
Conductor Type
Specify the material type of the phase conductor. The values are defined by the following
list (not limited to):
ACSR – for Aluminum Cable Steel Reinforced;
AL – for All Aluminum Conductor; and
CU – for Copper Conductor.
55 | P a g e
Conductor Size and Unit (C)
Specify the size of the phase conductor. The values are defined by the following list (not
limited to):
AWG;
CM; or
mm2.
Strands (C)
Specify the number of strands of the phase conductor. For ACSR, the number of strands
of the aluminum and steel shall be specified according to the following format:
Al/St
For example, an ACSR with 6 Aluminum strands and 1 Steel should have “6/1” entry in
the Strands field.
Neutral Wire Type
Specify the type of material of the Neutral Wire. The values are defined by the following
list (not limited to):
ACSR – for Aluminum Cable Steel Reinforced;
AL – for Aluminum Conductor; and
CU – for Copper Conductor.
Neutral Wire Size and Unit (NW)
Specify the size of the Neutral Wire. The values are defined by the following list (not
limited to):
AWG;
CM; or
mm2.
Strands (NW)
Specify the number of strands of the Neutral Wire. For ACSR, the number of strands of
the aluminum and steel shall be specified according to the following format:
Al/St
For example, an ACSR with 6 Aluminum strands and 1 Steel should have “6/1” entry in
the Strands field.
Spacing D12 (meters)
Specify the distance in meters between Conductor 1 and Conductor 2. See Figure 11.
Given the Phasing convention defined in the Phasing field, the conductor spacing
shall translate to the following:
a)
b)
c)
d)
e)
f)
56 | P a g e
For ABCN and ABC: D12 is the distance between Phase A and Phase B;
For ACBN and ACB: D12 is the distance between Phase A and Phase C;
For BCAN and BCA: D12 is the distance between Phase B and Phase C;
For BACN and BAC: D12 is the distance between Phase B and Phase A;
For CABN and CAB: D12 is the distance between Phase C and Phase A;
For CBAN and CBA: D12 is the distance between Phase C and Phase B;
g)
h)
i)
j)
k)
l)
m)
n)
o)
For ABN and AB: D12 is the distance between Phase A and Phase B;
For BAN and BA: D12 is the distance between Phase B and Phase A;
For BCN and BC: D12 is the distance between Phase B and Phase C;
For CBN and CB: D12 is the distance between Phase C and Phase B;
For CAN and CA: D12 is the distance between Phase C and Phase A;
For ACN and AC: D12 is the distance between Phase A and Phase C;
For AN: D12 = 0;
For BN: D12 = 0; and
For CN: D12 = 0;
Spacing D23 (meters)
Specify the distance in meters between Conductor 2 and Conductor 3. See Figure 11.
Given the Phasing convention defined in the Phasing field, the conductor spacing
shall translate to the following:
a)
b)
c)
d)
e)
f)
g)
h)
i)
j)
k)
l)
m)
n)
o)
For ABCN and ABC: D23 is the distance between Phase A and Phase B;
For ACBN and ACB: D23 is the distance between Phase A and Phase C;
For BCAN and BCA: D23 is the distance between Phase B and Phase C;
For BACN and BAC: D23 is the distance between Phase B and Phase A;
For CABN and CAB: D23 is the distance between Phase C and Phase A;
For CBAN and CBA: D23 is the distance between Phase C and Phase B;
For ABN and AB: D23 is the distance between Phase A and Phase B;
For BAN and BA: D23 is the distance between Phase B and Phase A;
For BCN and BC: D23 is the distance between Phase B and Phase C;
For CBN and CB: D23 is the distance between Phase C and Phase B;
For CAN and CA: D23 is the distance between Phase C and Phase A;
For ACN and AC: D23 is the distance between Phase A and Phase C;
For AN: D23 = 0;
For BN: D23 = 0; and
For CN: D23 = 0;
Spacing D13 (meters)
Specify the distance in meters between Conductor 1 and Conductor 3. See Figure 11.
Given the Phasing convention defined in the Phasing field, the conductor spacing
shall translate to the following:
a)
b)
c)
d)
e)
f)
g)
h)
i)
j)
k)
l)
m)
n)
o)
57 | P a g e
For ABCN and ABC: D13 is the distance between Phase A and Phase B;
For ACBN and ACB: D13 is the distance between Phase A and Phase C;
For BCAN and BCA: D13 is the distance between Phase B and Phase C;
For BACN and BAC: D13 is the distance between Phase B and Phase A;
For CABN and CAB: D13 is the distance between Phase C and Phase A;
For CBAN and CBA: D13 is the distance between Phase C and Phase B;
For ABN and AB: D13 is the distance between Phase A and Phase B;
For BAN and BA: D13 is the distance between Phase B and Phase A;
For BCN and BC: D13 is the distance between Phase B and Phase C;
For CBN and CB: D13 is the distance between Phase C and Phase B;
For CAN and CA: D13 is the distance between Phase C and Phase A;
For ACN and AC: D13 is the distance between Phase A and Phase C;
For AN: D13 = 0;
For BN: D13 = 0;
For CN: D13 = 0;
Spacing D1n (meters)
Specify the distance in meters between Conductor 1 and the Neutral Wire. See Figure 11.
Spacing D2n (meters)
Specify the distance in meters between Conductor 2 and the Neutral Wire. See Figure 11.
Spacing D3n (meters)
Specify the distance in meters between Conductor 3 and the Neutral Wire. See Figure 11.
Height H1 (meters)
Specify the height in meters of Conductor 1 of the Sub-Transmission Load Service Drop.
Specify the value “0.0” if not applicable. See Figure 11.
Height H2 (meters)
Specify the height in meters of Conductor 2 of the Sub-Transmission Load Service Drop.
Specify the value “0.0” if not applicable. See Figure 11.
Height H3 (meters)
Specify the height in meters of Conductor 3 of the Sub-Transmission Load Service Drop.
Specify the value “0.0” if not applicable. See Figure 11.
Height Hn (meters)
Specify the height in meters of the Neutral Wire of the Sub-Transmission Load Service
Drop. Specify the value “0.0” if not applicable. See Figure 11.
Figure 11. Conductor Arrangement
Earth Resistivity (Ohm-meter)
Specify the earth resistivity in ohm-meter. Use a value of 100 for average damp earth if
the value of resistivity is not known.
58 | P a g e
ERC-DSLSUBT-12:
Subtrans Svc Drop-Underground
Except for the following fields, the rest of the field names for the Subtrans Svc DropUnderground data are the same as for the Subtransmission Line-Underground data only
that the fields would correspond to a Load Service Drop rather than a Subtransmission
Line.
Sub-Transmission Load Service Drop ID
Specify the unique ID of the Sub-Transmission Load Service Drop segment using up to
25 alphanumeric characters.
To Load ID
Specify the unique ID of the receiving end of the Sub-Transmission Load Service Drop.
This Load ID must correspond to that specified in the Load Data.
ERC-DSLSUBT-13: Voltage Regulator Data
Voltage Regulator ID
Specify the unique ID for the Voltage Regulator using up to 25 alphanumeric
characters.
From Bus ID
Specify the Bus ID of the source side of the Voltage Regulator.
To Bus ID
Specify the Bus ID of the load side of the Voltage Regulator.
Regulated Bus ID
Specify the Bus ID of the regulating point (Bus or Node) whose voltage is being
controlled by the Voltage Regulator.
Phase Type
Specify the type of Voltage Regulator:
1
2
3
4
–
–
–
–
Single phase
Two single phase
Three-phase, gang operated
Three single phase, independently operated
Phasing
Specify the Phasing of the Voltage Regulator:
a) ABCN, ACBN, BCAN, BACN, CABN or CBAN for Multi-grounded Three
Phase System;
b) ABN, BAN, BCN, CBN, CAN or ACN for Multi-grounded V-Phase
System;
c) AN, BN or CN for Multi-grounded Single-Phase System;
d) ABC, ACB, BCA, BAC, CAB, CBA for Uni-grounded Three-Phase System;
and
e) AB, BA, BC, CB, CA or AC for Uni-grounded Single-Phase System.
Phase Sense
Specify the phase where the Voltage Sensor (PT) is installed:
A
B
C
59 | P a g e
–
–
–
if Phase A
if Phase B
if Phase C
kVA Rating
Specify the Rated Capacity of the Voltage Regulator in kVA.
kV Rating
Specify the voltage rating of the Voltage Regulator in kV.
Target Voltage (120V base)
Specify the desired voltage (on 120-volt base) to be held by the Voltage Regulator at
the regulating point (e.g., 124 volts).
Bandwidth (120V base)
Specify the voltage level tolerance of the Voltage Regulator on 120-volt base (e.g.
2.0 volts):
R-Setting Phase A
Specify the Compensator R-dial setting (i.e., the equivalent resistance to the
regulating point calibrated in volts) of the Voltage Regulator in Phase A. Enter “0.0”
if not applicable.
R-Setting Phase B
Specify the Compensator R-dial setting (i.e., the equivalent resistance to the
regulating point calibrated in volts) of the Voltage Regulator in Phase B. Enter “0.0”
if not applicable.
R-Setting Phase C
Specify the Compensator R-dial setting (i.e., the equivalent resistance to the
regulating point calibrated in volts) of the Voltage Regulator in Phase C. Enter “0.0”
if not applicable.
X-Setting Phase A
Specify the Compensator X-dial setting (i.e., the equivalent reactance to the
regulating point calibrated in volts) of the Voltage Regulator in Phase A. Enter “0.0”
if not applicable.
X-Setting Phase B
Specify the Compensator X-dial setting (i.e., the equivalent reactance to the
regulating point calibrated in volts) of the Voltage Regulator in Phase B. Enter “0.0”
if not applicable.
X-Setting Phase C
Specify the Compensator X-dial setting (i.e., the equivalent reactance to the
regulating point calibrated in volts) of the Voltage Regulator in Phase C. Enter “0.0”
if not applicable.
Primary Current Rating (A)
Specify the primary current rating of the Current Transformer used for the Voltage
Regulator. The CT secondary current is assumed 1 Ampere.
PT Ratio
Specify the voltage ratio of the Potential Transformer used for the Voltage
Regulator. Usually the PT secondary voltage of Voltage Regulator is 120 volts. For
example, a PT rated 13,200/120 volts has a PT Ratio of 110.
No-Load Loss (kW)
Specify the No-Load (fixed) loss of the Voltage Regulator in kW.
Exciting Current (%)
Specify the exciting current of the Voltage Regulator in percent (%) of the rated
current.
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ERC-DSLSUBT-13: Shunt Capacitor Data
Shunt Capacitor ID
Specify the unique ID for the Shunt Capacitor using up to 25 alphanumeric
characters.
Bus Connected (Bus ID)
Specify the Bus ID of the Bus or Node where the Shunt Capacitor is connected.
Phase Type
Specify the construction type of Shunt Capacitor:
1
2
3
4
–
–
–
–
Single-phase Shunt Capacitor
Two (2) single-phase Shunt Capacitors
Three-phase Shunt Capacitor
Three (3) single-phase Shunt Capacitors
Phasing
Specify the Phasing of the Shunt Capacitor:
a) ABC for Three-Phase;
b) AB, BC or CA for V-Phase; and
c) A, B, C for Single-Phase.
Voltage Rating (kV)
Specify the Voltage Rating of Shunt Capacitor in kV.
kVAR Rating Phase A
Specify reactive Power Rating in kVARs of the Shunt Capacitor in phase A.
kVAR Rating Phase B
Specify reactive Power Rating in kVARs of the Shunt Capacitor in phase B.
kVAR Rating Phase C
Specify reactive Power Rating in kVARs of the Shunt Capacitor in phase C.
Power Loss (Watts)
Specify the Power Losses of the Shunt Capacitor per phase in Watts. Use typical
value if Power Loss data of the Shunt Capacitor is not known.
ERC-DSLSUBT-14: Shunt Inductor Data
Shunt Inductor ID
Specify the unique ID for the Shunt Inductor using up to 25 alphanumeric
characters.
Bus Connected (Bus ID)
Specify the Bus ID of the Bus or Node where the Shunt Inductor is connected.
Phase Type
Specify the construction type of Shunt Inductor:
1
2
3
4
61 | P a g e
–
–
–
–
Single-phase Shunt Inductor
Two (2) Single-phase Shunt Inductors
Three-phase Shunt Inductor
Three (3) Single-phase Shunt Inductors
Phasing
Specify the Phasing of the Shunt Inductors:
a) ABC for Three-Phase;
b) AB, BC or CA for V-Phase; and
c) A, B, C for Single-Phase.
Voltage Rating (kV)
Specify the Voltage Rating of the Shunt Inductor in kV.
Resistance Phase A (Ohms)
Specify the Resistance in Ohms of the Shunt Inductor in Phase A. Use typical value if
the resistance of the resistance of the Shunt Inductor is not available.
Resistance Phase B (Ohms)
Specify the Resistance in Ohms of the Shunt Inductor in Phase B. Use typical value if
the resistance of the resistance of the Shunt Inductor is not available.
Resistance Phase C (Ohms)
Specify the Resistance in Ohms of the Shunt Inductor in Phase C. Use typical value if
the resistance of the resistance of the Shunt Inductor is not available.
Reactance Phase A (Ohms)
Specify the Reactance in Ohms of the Shunt Inductor in Phase A.
Reactance Phase B (Ohms)
Specify the Reactance in Ohms of the Shunt Inductor in Phase B.
Reactance Phase C (Ohms)
Specify the Reactance in Ohms of the Shunt Inductor in Phase C.
ERC-DSLSUBT-15: Series Inductor Data
Series Inductor ID
Specify the unique ID for the Series Inductor using up to 25 alphanumeric
characters.
From Bus ID
Specify the Bus ID of the source side of the Series Inductor.
To Bus ID
Specify the Bus ID of the load side of the Series Inductor.
Phase Type
Specify the construction type of Series Inductor:
1
2
3
4
–
–
–
–
One (1) Single-phase Series Inductor
Two (2) single-phase Series Inductors
One (1) Three-phase Series Inductor
Three (3) single-phase Series Inductors
Phasing
Specify the Phasing of the Series Inductors:
a) ABCN, ACBN, BCAN, BACN, CABN or CBAN for Multi-grounded ThreePhase System;
b) ABN, BAN, BCN, CBN, CAN or ACN for Multi-grounded V-Phase
System;
62 | P a g e
c) AN, BN or CN for Multi-grounded Single-Phase System;
d) ABC, ACB, BCA, BAC, CAB, CBA for Uni-grounded Three-Phase System;
and
e) AB, BA, BC, CB, CA or AC for Uni-grounded Single-Phase System;
Voltage Rating (kV)
Specify the Voltage Rating of the Series Inductor in kV.
Resistance Phase A (Ohms)
Specify the Resistance in Ohms of the Series Inductor in Phase A. Use typical value if
the resistance of the resistance of the Series Inductor is not available.
Resistance Phase B (Ohms)
Specify the Resistance in Ohms of the Series Inductor in Phase B. Use typical value if
the resistance of the resistance of the Series Inductor is not available.
Resistance Phase C (Ohms)
Specify the Resistance in Ohms of the Series Inductor in Phase C. Use typical value if
the resistance of the resistance of the Series Inductor is not available.
Reactance Phase A (Ohms)
Specify the Reactance in Ohms of the Series Inductor in Phase A.
Reactance Phase B (Ohms)
Specify the Reactance in Ohms of the Series Inductor in Phase B.
Reactance Phase C (Ohms)
Specify the Reactance in Ohms of the Series Inductor in Phase C.
B.2
Monthly Feeder DSL Data
The Distribution Utility shall submit the monthly feeder DSL data in the format
described in the following templates:
a) ERC-DSL-00: DSL FDR Simulation Parameters;
b) ERC-DSL-01: Customer Data;
c) ERC-DSL-02: Billing Cycle Data;
d) ERC-DSL-03: Customer Energy Consumption Data;
e) ERC-DSL-04: Load Curve Data;
f) ERC-DSL-05: Bus Data;
g) ERC-DSL-06: Primary Distribution Line Data – Overhead;
h) ERC-DSL-07: Primary Distribution Line Data – Underground Cable;
i) ERC-DSL-08: Primary Customer Service Drop Data – Overhead;
j) ERC-DSL-09: Primary Customer Service Drop Data – Underground Cable;
k) ERC-DSL-10: Distribution Transformer Data
l) ERC-DSL-11: Secondary Distribution Line Data
m) ERC-DSL-12: Secondary Customer Service Drop Data;
n) ERC-DSL-13: Voltage Regulator Data;
o) ERC-DSL-14: Shunt Capacitor Data;
p) ERC-DSL-15: Shunt Inductor Data; and
q) ERC-DSL-16: Series Inductor Data.
63 | P a g e
ERC-DSL-00:
DSL-FDR Simulation Parameters
This data describe the parameters that will be used in the simulation of DSL for the
Feeder data.
Feeder Root Bus ID
Specify the Bus ID of the root connection point for the Feeder. This ID must be found in
the Bus Data sheet.
Feeder Energy Input (kWh)
Specify the energy input in kWh for the Feeder for a particular Billing Cycle. This is the
energy that was purchased by the DU for the Feeder for the given billing period.
DU Use (kWh)
Specify the energy in kWh used by the DU for its operation for the Feeder for a particular
Billing Cycle.
Power Mismatch
Specify the Power Mismatch that will be used as convergence criteria for the load flow
simulation. Once the computed power mismatch value is less than the specified value,
the load flow simulation considers the solution as convergent (or has arrived at a fixed
value), otherwise, the process will continue to iterate until power mismatch is less than
the specified value or until the process has reached the specified Maximum Iteration.
(Typical value for Power Mismatch is 0.00001)
Base kVA
Specify the Base kVA that will be used in converting the network models to per unit. This
process is done before the actual load flow simulation process. (Typical value for Base
kVA is 15)
Maximum Iteration
Specify the Maximum Iteration that will be used as stopping criteria for the load flow
simulation. For each iteration of the load flow process, the computed power mismatch is
compared to the specified Power Mismatch. When the computed power mismatch value
is greater than the specified Power Mismatch, the load flow process continues to iterate.
The Maximum Iteration field will serve to stop the simulation if it has reached the
maximum number of iteration regardless if the simulation has reached a convergent
solution or not. (Typical value for Maximum Iteration is 50)
Percent PQ
Specify the Percent PQ that will be used for the modeling of the loads or customers for
the given data. Percent PQ signifies the percentage of all loads or customers that are
considered or behave as constant power loads. (Typical value for Percent PQ is 100)
Percent Z
Specify the Percent Z that will be used for the modeling of the loads or customers for the
given data. Percent Z signifies the percentage of all loads or customers that are
considered or behave as constant impedance loads. (Typical value for Percent Z is 0)
64 | P a g e
Percent Loading
Specify the Percent Loading that will be used for the aggregate scaling of all the
connected loads or customers for the given data. A Percent Loading value of 90 signifies
that all the customer loads are scaled by 90%. (Typical value for Percent Loading is 100)
Source Voltage Hour 1-24
Specify the hourly voltage profile in per unit at the Source or Root Bus of the Feeder.
(Typical value for Source Voltage per hour is 1.0)
ERC-DSL-01:
Customer Data
Customer ID
Specify the unique ID that will identify a customer (e.g. Customer Account Number).
All customers must be included in the list.
Customer Name
Specify the name of the Load that corresponds to the Customer ID.
Customer Type
Specify the customer type or classification code using up to 25 characters (e.g., RES1
for small residential, RES2 for large residential, etc.). All Load Types used in this list
must be defined in the Load Curve Data.
Service Voltage
Specify the nominal service voltage being supplied to the customer in kV (e.g. 13.2).
Phase
Specify the number of phase(s) of the load service.
1 – Single-Phase, or
3 – Three-Phase
ERC-DSL-02: Billing Cycle Data
Billing Period Code
Specify the Billing Period according to the following coding system:
YYYYMM
Where YYYY – Year of the meter reading period (e.g. 2017 for year 2017)
MM – Month of the meter reading period (e.g. 08 for August)
Period Covered
Specify the month, day, and year covered by the Billing Cycle.
Number of Days
Specify the number of days covered by the Billing Period.
Number of Hours
Specify the total number of hours covered by the Billing Period.
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ERC-DSL-03: Customer Energy Consumption Data
Customer ID
Specify the unique ID that identifies a customer. This must be the same ID used in the
Customer Data.
Billing Period Code
Specify the Billing Period according to the following coding system:
YYYYMM
Where YYYY – Year of the meter reading period (e.g. 2017 for year 2017)
MM – Month of the meter reading period (e.g. 08 for August)
Energy Consumed (kWh)
Specify the energy consumption in kWh of the load for the Billing Period (e.g. meter
reading for a specific feeder).
Power Factor
Specify the average power factor (measured or estimated) of the load for the Billing
Period.
ERC-DSL-04: Load Curve Data
Load Curve ID
Specify the unique ID of the load curve for the Load Type.
Customer Type
Specify the type or classification of the customer represented by the load curve. This
must be corresponding to the Customer Type specified in the Customer Data.
Description
Specify the description of the Customer Type.
Hour 1 to Hour 24
Specify the normalized hourly demand from Hour 1 to Hour 24 of the Load Curve in per
unit. This can be obtained by monitoring the 24-hour demand pattern of the Load Type
(e.g. hourly Ampere, kW, kVA, etc.). To obtain the normalized demand in per unit, each
hourly demand is divided by the peak demand. Thus, the highest value of the normalized
hourly demand is 1.0 which coincides with the peak hour.
ERC-DSL-05: Bus Data
Bus ID
Specify the unique ID of the Bus or Node in the Primary and Secondary Distribution
System using up to 25 alphanumeric characters. Bus or node is created for each
connection or junction point from the Primary Distribution Lines to the Secondary
Distribution Lines.
Description
Specify the description of the Bus or Node.
Nominal Voltage (kV)
Specify the nominal voltage of the Bus or Node in kV (e.g. 13.2, 0.24).
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ERC-DSL-06: Primary Distribution Line Data – Overhead
Each Primary Distribution Line segment (i.e., the section of the Primary Distribution
Line that can be identified by only one sending-end and only one receiving-end)
must be included as one data entry. The whole length of the Distribution Line may
be entered as one or more line segments depending on the connection points and
the construction arrangement (e.g., loop, expanded radial, etc.).
Connection point is created if an equipment (e.g., Shunt Capacitor), line, or load is
connected to the Distribution Line. This connection point must be assigned a Bus ID.
[Note: Unless a “Connection Point” is created, a “Pole-to-Pole” line segment should
not be treated as a Primary Distribution Line Segment to avoid increasing the
number of Buses]
Primary Distribution Line Segment ID
Enter the unique ID of the Primary Distribution Line segment using up to 25
alphanumeric characters.
From Bus ID
Specify the Bus ID of the sending end of the Primary Distribution Line segment.
To Bus ID
Specify the Bus ID of the receiving end of the Primary Distribution Line segment.
Phasing
To distinguish the Primary Distribution Lines with grounded Neutral Wire from those
without grounded wire, the following Phasing convention shall be used:
a) For Uni-grounded Distribution System: ABC; and
b) For Multi-grounded Distribution System: ABCN.
In specifying the Phasing, conductor 1 shall be assumed to be always in the leftmost
side when facing the secondary side of the Substation Power Transformer for
triangular and horizontal configuration or the highest conductor in the case of
vertical configuration. Phasing shall be specified using the following conventions
(see Figure 11):
a) ABCN or ABC if Phases A, B and C correspond to conductor 1, 2 and 3,
respectively;
b) ACBN or ACB if Phases A, C and B correspond to conductor 1, 2 and 3,
respectively;
c) BCAN or BCA if Phases B, C and A correspond to conductor 1, 2 and 3,
respectively;
d) BACN or BAC if Phases B, A and C correspond to conductor 1, 2 and 3,
respectively;
e) CABN or CAB if Phases C, A and B correspond to conductor 1, 2 and 3,
respectively;
f) CBAN or CBA if Phases C, B and A correspond to conductor 1, 2 and 3,
respectively;
g) ABN or AB if Phases A and B correspond to conductor 1 and 2, respectively;
h) BAN or BA if Phases B and A correspond to conductor 1 and 2, respectively;
i) BCN or BC if Phases B and C correspond to conductor 1 and 2, respectively;
j) CBN or CB if Phases C and B correspond to conductor 1 and 2, respectively;
k) CAN or CA if Phases C and A correspond to conductor 1 and 2, respectively;
l) ACN or AC if Phases A and C correspond to conductor 1 and 2, respectively;
m) AN if Phase A corresponds to conductor 1;
n) BN if Phase A corresponds to conductor 1; and
o) CN if Phase A corresponds to conductor 1.
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Configuration
Specify installation configuration of conductors (see Figure 11):
Triangular;
Horizontal; or
Vertical.
System Grounding Type
Specify the system grounding type:
Uni-grounded; or
Multi-grounded.
Length (meters)
Enter the length of the Primary Distribution Line segment in meters.
Conductor Type
Specify the material type of the phase conductor:
ACSR – for Aluminum Cable Steel Reinforced;
AL
– for Aluminum Conductor; and
CU
– for Copper Conductor
Conductor Size and Unit (C)
Specify size of phase conductors in AWG, CM or mm2
Strands (C)
Specify the number of strands of the phase conductors. For ACSR, the number of
strands of the aluminum and steel shall be specified according to the following format:
Al/St
For example, an ACSR with 6 Aluminum strands and 1 Steel should have “6/1” entry
in the Strands column.
Neutral Wire Type
Specify the material type of the Neutral Wire:
ACSR –
for Aluminum Cable Steel Reinforced;
AL – for Aluminum Conductor; and
CU – for Copper Conductor.
Neutral Wire Size and Unit (NW)
Specify size of Neutral Wire in AWG, CM or mm2
Strands (NW)
Specify the number of strands of the Neutral Wire. For ACSR, the number of strands of
the aluminum and steel shall be specified according to the following format:
Al/St
For example, an ACSR with 6 Aluminum strands and 1 Steel should have “6/1” entry in
the Strands column.
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Spacing D12 (meters)
Specify the distance in meters between Conductor 1 (leftmost conductor for
triangular and horizontal configuration or the highest conductor for vertical
configuration) and Conductor 2 (middle conductor). This Phasing convention shall
translate to the following conductors spacing (see Figure 11):
a)
b)
c)
d)
e)
f)
g)
h)
i)
j)
k)
l)
m)
n)
o)
For ABCN and ABC: D12 is the distance between Phase A and Phase B;
For ACBN or ACB: D12 is the distance between Phase A and Phase C;
For BCAN or BCA: D12 is the distance between Phase B and Phase C;
For BACN or ABC: D12 is the distance between Phase B and Phase A;
For CABN or CAB: D12 is the distance between Phase C and Phase A;
For CBA or CBA: D12 is the distance between Phase C and Phase B;
For ABN or AB: D12 is the distance between Phase A and Phase B;
For BAN or BA: D12 is the distance between Phase B and Phase A;
For BCN or BC: D12 is the distance between Phase B and Phase C;
For CBN or CB: D12 is the distance between Phase C and Phase B;
For CAN or CA: D12 is the distance between Phase A and Phase B;
For ACN or AC: D12 is the distance between Phase A and Phase C;
For AN: D12 = 0;
For BN: D12 = 0; and
For CN: D12 =0;
Spacing D23 (meters)
Specify the distance in meters between Conductor 2 (middle conductor) and
Conductor 3 (rightmost conductor for triangular and horizontal configuration or the
lowest conductor for vertical configuration). This Phasing convention shall translate
to the following conductors spacing (see Figure 11):
a)
b)
c)
d)
e)
f)
g)
h)
i)
j)
k)
l)
m)
n)
o)
For ABCN and ABC: D23 is the distance between Phase B and Phase C;
For ACBN or ACB: D23 is the distance between Phase C and Phase B;
For BCAN or BCA: D23 is the distance between Phase C and Phase A;
For BACN or ABC: D23 is the distance between Phase A and Phase C;
For CABN or CAB: D23 is the distance between Phase A and Phase B;
For CBA or CBA: D23 is the distance between Phase B and Phase A;
For ABN or AB: D23 = 0;
For BAN or BA: D23 = 0;
For BCN or BC: D23 = 0;
For CBN or CB: D23 = 0;
For CAN or CA; D23 = 0;
For ACN or AC; D23 = 0;
For AN: D23 = 0;
For BN: D23 = 0;
For CN: D23 = 0.
Spacing D13 (meters)
Specify the distance in meters between Conductor 1 (leftmost conductor for
triangular and horizontal configuration or the highest conductor for vertical
configuration) and Conductor 3 (rightmost conductor for triangular and
horizontal configuration or the lowest conductor for vertical configuration). This
Phasing convention shall translate to the following conductors spacing (see Figure
11):
a)
b)
c)
d)
e)
f)
g)
h)
i)
69 | P a g e
For ABCN and ABC: D13 is the distance between Phase A and Phase C;
For ACBN or ACB: D13 is the distance between Phase A and Phase B;
For BCAN or BCA: D13 is the distance between Phase B and Phase A;
For BACN or ABC: D13 is the distance between Phase B and Phase C;
For CABN or CAB: D13 is the distance between Phase C and Phase B;
For CBA or CBA: D13 is the distance between Phase C and Phase A
For ABN or AB: D13 = 0;
For BAN or BA: D13 = 0;
For BCN or BC: D13 = 0;
j)
k)
l)
m)
n)
o)
For CBN or CB: D13 = 0;
For CAN or CA: D13 = 0;
For ACN or AC: D13 = 0;
For AN: D13 = 0;
For BN: D13 = 0; and
For CN: D13 = 0.
Spacing D1n (meters)
Specify the distance in meters between Conductor 1 and the Neutral Wire.
Spacing D2n (meters)
Specify the distance in meters between Conductor 2 and the Neutral Wire.
Spacing D3n (meters)
Specify the distance in meters between Conductor 3 and the Neutral Wire.
Height H1 (meters)
Specify the height of Conductor 1 of the Primary Distribution Line Segment from the
earth in meters. Enter “0.0” if not applicable.
Height H2 (meters)
Specify the height of Conductor 2 of the Primary Distribution Line Segment from the
earth in meters. Enter “0.0” if not applicable.
Height H3 (meters)
Specify the height of Conductor 3 of the Primary Distribution Line Segment from the
earth in meters. Enter “0.0” if not applicable.
Height Hn (meters)
Specify the height of the Neutral Wire from the earth in meters. Enter “0.0” if
not applicable.
Earth Resistivity (Ohm-meter)
Specify the earth resistivity in ohm-meter. Use 100 ohm-meters for average damp
earth if the value of resistivity is not known.
ERC-DSL-07: Primary Distribution Line Data – Underground Cable
Primary Line Segment ID
Specify the unique ID of the Primary Distribution Line segment using up to 25
alphanumeric characters.
From Bus ID
Specify the unique ID of the sending end of the Primary Distribution Line segment. This
Bus ID must correspond to that specified in the Bus Data.
To Bus ID
Specify the unique ID of the receiving end of the Primary Distribution Line segment.
This Bus ID must correspond to that specified in the Bus Data.
Phasing
Specify the phase arrangement of the Primary Distribution Line segment.
ABC, ACB, BCA, BAC, CAB, or CBA.
In specifying the Phasing, conductor 1 shall be assumed to be always in the leftmost side
when facing the secondary side of the Substation Power Transformer for triangular and
70 | P a g e
horizontal configuration or the highest conductor in the case of vertical configuration as
illustrated in Figure 3.
Length (meters)
Specify the length of the Primary Distribution Line segment in meters.
Conductor Type
Specify the material type of the phase conductor. The values are defined by the following
list (not limited to):
AL – for All Aluminum Conductor; and
CU – for Copper Conductor.
Conductor Size and Unit (C)
Specify the size of the phase conductor. The values are defined by the following list (not
limited to):
AWG;
CM; or
mm2.
No. of Cores (C)
Specify the number of cores of the cable. The values are defined by the following:
1 – Single-Core Cable;
2 – Two-Core Cable;
3 – Three-Core Cable;
4 – Four-Core Cable.
Diameter under Armor (mm)
Specify the diameter under the Armor Wire in millimeters. See Figure 10.
Armor Wire Diameter (mm)
Specify the diameter of the Armor Wire in millimeters. See Figure 10.
Overall Diameter (mm)
Specify the overall diameter of the cable in millimeters. See Figure 10.
AC Resistance (ohm/km)
Specify the AC resistance of the conductor in ohm/km.
Inductive Reactance (ohm/km)
Specify the inductive reactance of the cable in ohm/km.
Capacitance (micro-farad/km)
Specify the star capacitance of the cable in micro-farad/km.
Earth Resistivity (ohm-meter)
Specify the earth resistivity in ohm-meter. Use a value of 100 for average damp earth if
the value of resistivity is not known.
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ERC-DSL-08: Primary Customer Service Drop Data – Overhead
The Primary Customer Service Drop is the conductor extended from the Primary
Distribution Line to the customer service entrance. The data for the Primary Overhead
Distribution Customer Service Drops are the same as the requirements for the
Primary Overhead Distribution Line (ERC-DSL-07) except for the Primary Customer
Service Drop ID.
ERC-DSL-09: Primary Customer Service Drop Data – Underground
Cable
The data for the Primary Underground Distribution Customer Service Drops are the
same as the requirements for the Primary Underground Distribution Line except for
the Primary Customer Service Drop ID.
ERC-DSL-10: Distribution Transformer Data
Distribution Transformer ID
Specify the unique ID for the Distribution Transformer using up to 25 alphanumeric
characters.
From Primary Bus ID
Specify the Bus ID where the primary of the Distribution Transformer is connected.
To Secondary Bus ID
Specify the Bus ID where the secondary of the Distribution Transformer is connected.
Phasing
Specify the Phasing of the Distribution Transformer (at the secondary terminals):
a) ABCN, ACBN, BCAN, BACN, CABN or CBAN for Multi-grounded Three- Phase
Transformer bank;
b) ABN, BAN, BCN, CBN, CAN or ACN for Multi-grounded V-Phase Transformer
bank;
c) AN, BN or CN for Multi-grounded Single-Phase Transformer
d) ABC, ACB, BCA, BAC, CAB, CBA for Uni-grounded Three-Phase Transformer
bank;
e) AB, BA, BC, CB, CA or AC for Uni-grounded Single-Phase Transformer.
Installation Type
Specify the Installation Type of the Distribution Transformer:
Pole-mounted or Pad-mounted
No. of DTs in Bank
Specify the number of Distribution Transformer in bank:
1
2
3
4
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–
–
–
–
One (1) Single-phase Distribution Transformer
Two (2) Single-phase Distribution Transformers
One (1) Three-phase Distribution Transformer
Three (3) Single-phase Distribution Transformers
Connection
Specify the connection of the Distribution Transformer:
1
2
3
4
5
6
7
8
9
10
11
12
–
–
–
–
–
–
–
–
–
–
–
–
Single Phase
Delta-Delta
Delta-WyeGrnd
Delta-Wye
WyeGrnd-WyeGrnd
WyeGrnd-Wye
Wye-WyeGrnd
Wye-Wye
WyeGrnd-Delta
Wye-Delta
Open Delta-Open Delta
Open Wye-Open Delta
kVA Rating
Specify the Rated Capacity of the Distribution Transformer in kVA. For two (2) or
three (3) single-phase transformers in a bank, the rated kVA of the largest
Distribution Transformer shall be used.
Primary Voltage Rating (kV)
Specify the Voltage Rating of the primary winding of the Distribution Transformer in
kV. The voltage rating should be taken from the nameplate and not the resulting
line-to-line voltage of the transformer bank.
Secondary Voltage Rating (kV)
Specify the Voltage Rating of the secondary winding of the Distribution Transformer
in kV. The voltage rating should be taken from the nameplate and not the resulting
line-to-line voltage of the transformer bank.
Primary Tap Voltage (kV)
Specify the Primary Tap Voltage of the Distribution Transformer in kV. Enter the
Rated Primary Voltage if the Distribution Transformer has no taps in the primary.
Secondary Tap Voltage (kV)
Specify the Secondary Tap Voltage of the Distribution Transformer in kV. Enter the
Rated Secondary Voltage if the Distribution Transformer has no taps in the
secondary.
%Z
Specify the percent impedance (%Z) of the Distribution Transformer taken from the
nameplate. Use typical value if %Z is not available.
X/R Ratio
Specify the X/R Ratio of the impedance of the Distribution Transformer. Use typical
value if X/R Ratio is not available.
No-Load Loss (kW)
Specify the No-load loss of the Distribution Transformer in kW. Use typical value if
X/R Ratio is not available.
Exciting Current (%)
Specify the exciting current of the Distribution Transformer in percent (%) of the
rated current. Use typical value if exciting current is not available.
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ERC-DSL-11: Secondary Distribution Line Data
Each Secondary Distribution Line segment (i.e., the section of the Secondary
Distribution Line that can be identified by only one sending-end and only one
receiving-end) must be included as one data entry. The whole length of the
Secondary Line may be entered as one or more line segments depending on the
connection points created by secondary lateral lines or service drops.
Secondary Distribution Line ID
Enter the unique ID of the Secondary Distribution Line segment using up to 25
alphanumeric characters.
From Bus ID
Specify the Bus ID of the sending end of the Secondary Distribution Line segment.
To Bus ID
Specify the Bus ID of the receiving end of the Secondary Distribution Line segment.
Phasing
Specify the Phasing of the Secondary Distribution Line:
a) ABCN, ACBN, BCAN, BACN, CABN or CBAN for 4-wire three-phase Secondary
System;
b) ABC, ACB, BCA, BAC, CAB, CBA for 3-wire three-Phase Secondary System;
c) ABN, BAN, BCN, CBN, CAN or ACN for 3-wire single-phase Secondary System;
d) AN, BN or CN for 2-wire single-phase Secondary System;
Installation Type
Specify the type of installation of the secondary distribution line segment:
1 – Overhead, underbuilt;
2 – Overhead, open secondary;
3 – Underground in magnetic raceway (e.g., Rigid Steel Conduit);
4 – Underground in non-magnetic raceway (e.g., PVC).
Length (meters)
Specify the length of the Secondary Distribution Line segment in meters.
Type
Specify the material type of the conductors:
ACSR – for Aluminum Cable Steel Reinforced;
AL
– for Aluminum Conductor; or
CU
– for Copper Conductor.
Conductor Size and Unit
Specify size of phase conductors in AWG, CM or mm2.
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ERC-DSL-12: Secondary Customer Service Drop Data
The Secondary Customer Service Drop is the conductor extended from the
Secondary Distribution Line or directly from the Distribution Transformer to the
customer service entrance.
Secondary Customer Service Drop ID
Enter the unique ID of the Secondary Customer Service Drop using up to 25
alphanumeric characters.
From Bus ID
Specify the Bus ID of the sending end of the Secondary Customer Service Drop.
To Customer ID
Specify the Customer ID of the customer that is connected at the end of the
Secondary Customer Service Drop.
Phasing
Specify the Phasing of the Secondary Customer Service Drop:
a) ABCN, ACBN, BCAN, BACN, CABN or CBAN for 4-wire three-phase Secondary
Service;
b) ABC, ACB, BCA, BAC, CAB, CBA for 3-wire three-Phase Secondary Service;
c) ABN, BAN, BCN, CBN, CAN or ACN for 3-wire single-phase Secondary Service;
and
d) AN, BN or CN for 2-wire single-phase Secondary Service.
Installation Type
Enter the type of installation of the Secondary Customer Service Drop:
1 – Overhead (or Arial);
2 – Underground in magnetic Raceway (e.g., Rigid Steel Conduit);
3 – Underground in non-magnetic Raceway (e.g., PVC).
Length-1 (meters)
Enter the length in meters of the Secondary Customer Service Drop from the Secondary
Distribution Line or from the Distribution Transformer Connection Point to the
Metering Point.
Length-2 (meters)
Enter the length in meters of the Secondary Customer Service Drop from the
Metering Point to Connection Point of the Customer.
Conductor Type
Specify the material type of the conductors:
ACSR – for Aluminum Cable Steel Reinforced;
AL
– for Aluminum Conductor; or
CU
– for Copper Conductor.
Conductor Size and Unit
Specify size of phase conductors in AWG, CM or mm2.
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ERC-DSL-13: Voltage Regulator Data
Voltage Regulator ID
Specify the unique ID for the Voltage Regulator using up to 25 alphanumeric
characters.
From Bus ID
Specify the Bus ID of the source side of the Voltage Regulator.
To Bus ID
Specify the Bus ID of the load side of the Voltage Regulator.
Regulated Bus ID
Specify the Bus ID of the regulating point (Bus or Node) whose voltage is being
controlled by the Voltage Regulator.
Phase Type
Specify the type of Voltage Regulator:
1
2
3
4
–
–
–
–
Single phase
Two single phase
Three-phase, gang operated
Three single phase, independently operated
Phasing
Specify the Phasing of the Voltage Regulator:
a) ABCN, ACBN, BCAN, BACN, CABN or CBAN for Multi-grounded Three
Phase System;
b) ABN, BAN, BCN, CBN, CAN or ACN for Multi-grounded V-Phase
System;
c) AN, BN or CN for Multi-grounded Single-Phase System;
d) ABC, ACB, BCA, BAC, CAB, CBA for Uni-grounded Three-Phase System;
and
e) AB, BA, BC, CB, CA or AC for Uni-grounded Single-Phase System.
Phase Sense
Specify the phase where the Voltage Sensor (PT) is installed:
A
B
C
–
–
–
if Phase A
if Phase B
if Phase C
kVA Rating
Specify the Rated Capacity of the Voltage Regulator in kVA.
kV Rating
Specify the voltage rating of the Voltage Regulator in kV.
Target Voltage (120V base)
Specify the desired voltage (on 120-volt base) to be held by the Voltage Regulator at
the regulating point (e.g., 124 volts).
Bandwidth (120V base)
Specify the voltage level tolerance of the Voltage Regulator on 120-volt base (e.g. 2.0
volts):
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R-Setting Phase A
Specify the Compensator R-dial setting (i.e., the equivalent resistance to the
regulating point calibrated in volts) of the Voltage Regulator in Phase A. Enter “0.0”
if not applicable.
R-Setting Phase B
Specify the Compensator R-dial setting (i.e., the equivalent resistance to the
regulating point calibrated in volts) of the Voltage Regulator in Phase B. Enter “0.0”
if not applicable.
R-Setting Phase C
Specify the Compensator R-dial setting (i.e., the equivalent resistance to the
regulating point calibrated in volts) of the Voltage Regulator in Phase C. Enter “0.0”
if not applicable.
X-Setting Phase A
Specify the Compensator X-dial setting (i.e., the equivalent reactance to the
regulating point calibrated in volts) of the Voltage Regulator in Phase A. Enter “0.0”
if not applicable.
X-Setting Phase B
Specify the Compensator X-dial setting (i.e., the equivalent reactance to the
regulating point calibrated in volts) of the Voltage Regulator in Phase B. Enter “0.0”
if not applicable.
X-Setting Phase C
Specify the Compensator X-dial setting (i.e., the equivalent reactance to the
regulating point calibrated in volts) of the Voltage Regulator in Phase C. Enter “0.0”
if not applicable.
Primary Current Rating (A)
Specify the primary current rating of the Current Transformer used for the Voltage
Regulator. The CT secondary current is assumed 1 Ampere.
PT Ratio
Specify the voltage ratio of the Potential Transformer used for the Voltage
Regulator. Usually the PT secondary voltage of Voltage Regulator is 120 volts. For
example, a PT rated 13,200/120 volts has a PT Ratio of 110.
No-Load Loss (kW)
Specify the No-Load (fixed) loss of the Voltage Regulator in kW.
Exciting Current (%)
Specify the exciting current of the Voltage Regulator in percent (%) of the rated
current.
ERC-DSL-14: Shunt Capacitor Data
Shunt Capacitor ID
Specify the unique ID for the Shunt Capacitor using up to 25 alphanumeric characters.
Bus Connected (Bus ID)
Specify the Bus ID of the Bus or Node where the Shunt Capacitor is connected.
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Phase Type
Specify the construction type of Shunt Capacitor:
1
2
3
4
–
–
–
–
Single-phase Shunt Capacitor
Two (2) single-phase Shunt Capacitors
Three-phase Shunt Capacitor
Three (3) single-phase Shunt Capacitors
Phasing
Specify the Phasing of the Shunt Capacitor:
a) ABC for Three-Phase;
b) AB, BC or CA for V-Phase; and
c) A, B, C for Single-Phase.
Voltage Rating (kV)
Specify the Voltage Rating of Shunt Capacitor in kV.
kVAR Rating Phase A
Specify reactive Power Rating in kVArs of the Shunt Capacitor in phase A.
kVAR Rating Phase B
Specify reactive Power Rating in kVArs of the Shunt Capacitor in phase B.
kVAR Rating Phase C
Specify reactive Power Rating in kVArs of the Shunt Capacitor in phase C.
Power Loss (Watts)
Specify the Power Losses of the Shunt Capacitor per phase in Watts. Use typical
value if Power Loss data of the Shunt Capacitor is not known.
ERC-DSL-15: Shunt Inductor Data
Shunt Inductor ID
Specify the unique ID for the Shunt Inductor using up to 25 alphanumeric
characters.
Bus Connected (Bus ID)
Specify the Bus ID of the Bus or Node where the Shunt Inductor is connected.
Phase Type
Specify the construction type of Shunt Inductor:
1
2
3
4
–
–
–
–
Single-phase Shunt Inductor
Two (2) Single-phase Shunt Inductors
Three-phase Shunt Inductor
Three (3) Single-phase Shunt Inductors
Phasing
Specify the Phasing of the Shunt Inductors:
a) ABC for Three-Phase;
b) AB, BC or CA for V-Phase;
c) A, B, C for Single-Phase.
Voltage Rating (kV)
Specify the Voltage Rating of the Shunt Inductor in kV.
78 | P a g e
Resistance Phase A (Ohms)
Specify the Resistance in Ohms of the Shunt Inductor in Phase A. Use typical value if
the resistance of the resistance of the Shunt Inductor is not available.
Resistance Phase B (Ohms)
Specify the Resistance in Ohms of the Shunt Inductor in Phase B. Use typical value if
the resistance of the resistance of the Shunt Inductor is not available.
Resistance Phase C (Ohms)
Specify the Resistance in Ohms of the Shunt Inductor in Phase C. Use typical value if
the resistance of the resistance of the Shunt Inductor is not available.
Reactance Phase A (Ohms)
Specify the Reactance in Ohms of the Shunt Inductor in Phase A.
Reactance Phase B (Ohms)
Specify the Reactance in Ohms of the Shunt Inductor in Phase B.
Reactance Phase C (Ohms)
Specify the Reactance in Ohms of the Shunt Inductor in Phase C.
ERC-DSL-16: Series Inductor Data
Series Inductor ID
Specify the unique ID for the Series Inductor using up to 25 alphanumeric
characters.
From Bus ID
Specify the Bus ID of the source side of the Series Inductor.
To Bus ID
Specify the Bus ID of the load side of the Series Inductor.
Phase Type
Specify the construction type of Series Inductor:
1
2
3
4
–
–
–
–
One (1) Single-phase Series Inductor
Two (2) single-phase Series Inductors
One (1) Three-phase Series Inductor
Three (3) single-phase Series Inductors
Phasing
Specify the Phasing of the Series Inductors:
a) ABCN, ACBN, BCAN, BACN, CABN or CBAN for Multi-grounded ThreePhase System;
b) ABN, BAN, BCN, CBN, CAN or ACN for Multi-grounded V-Phase
System;
c) AN, BN or CN for Multi-grounded Single-Phase System;
d) ABC, ACB, BCA, BAC, CAB, CBA for Uni-grounded Three-Phase System;
and
e) AB, BA, BC, CB, CA or AC for Uni-grounded Single-Phase System;
Voltage Rating (kV)
Specify the Voltage Rating of the Series Inductor in kV.
Resistance Phase A (Ohms)
Specify the Resistance in Ohms of the Series Inductor in Phase A. Use typical value if
the resistance of the resistance of the Series Inductor is not available.
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Resistance Phase B (Ohms)
Specify the Resistance in Ohms of the Series Inductor in Phase B. Use typical value if
the resistance of the resistance of the Series Inductor is not available.
Resistance Phase C (Ohms)
Specify the Resistance in Ohms of the Series Inductor in Phase C. Use typical value if
the resistance of the resistance of the Series Inductor is not available.
Reactance Phase A (Ohms)
Specify the Reactance in Ohms of the Series Inductor in Phase A.
Reactance Phase B (Ohms)
Specify the Reactance in Ohms of the Series Inductor in Phase B.
Reactance Phase C (Ohms)
Specify the Reactance in Ohms of the Series Inductor in Phase C.
B.3
Energy Quantities, Network Parameters, and CAPEX/OPEX Programs
The Distribution Utility shall submit the summary of energy quantities, relevant
network parameters and the list of CAPEX and OPEX programs related to the
Technical Loss and Non-Technical Loss reduction programs. These data should
be according to the format described in the following templates:
a)
b)
c)
d)
e)
f)
g)
h)
i)
ERC-DSLCAP-01:
ERC-DSLCAP-02:
ERC-DSLCAP-03:
ERC-DSLCAP-04:
ERC-DSLCAP-05:
ERC-DSLCAP-06:
ERC-DSLCAP-07:
ERC-DSLCAP-08:
ERC-DSLCAP-09:
Annual DSL Summary
Energy Input
Energy Output
Number of Customers
Distribution Feeder List
Distribution Substation List
DSL CAPEX & OPEX
DU Use Load Data
Actual Segregated DSL Data
ERC-DSLCAP-01: Annual DSL Summary
Distribution Utility
Specify the abbreviated name of the Distribution System.
Year
Specify the year for which the submitted data represents. (Format: YYYY; e.g. 2017)
Total Energy Input (kWh)
Specify the annual metered energy input in kWh to the entire Distribution System. This
is the energy delivered to the Distribution System by the Transmission System,
Embedded Generators, other Distribution Systems, and User Systems with generating
facilities.
Total Energy Output (kWh)
Specify the annual Energy Output in kWh of the entire Distribution System. This is the
energy delivered to the Users of the Distribution System including the energy for
Distribution Utility Use.
80 | P a g e
Distribution Utility Use (kWh)
Specify the annual aggregate of energy used for the proper operation of the distribution
system (e.g. for offices, administrative functions, etc.).
Total Number of Substations
Specify the total number of substations present in the entire Distribution System.
Total Number of Feeders
Specify the total number of feeders connected to the entire Distribution System.
Total Number of Customers
Specify the total number of customers connected to the entire Distribution System.
Peak Demand (MW)
Specify the maximum value of power, measured in MW, required by the Distribution
System for the specific year.
Primary Lines Total Circuit Length (meters)
Specify the total length, in meters, of lines in the Primary Distribution System delineated
by the secondary side of the Substation transformer and the primary side of all
distribution transformers.
Secondary Lines Total Circuit Length (meters)
Specify the total length, in meters, of lines in the Secondary Distribution System, the
portion of the Distribution System that is at the secondary side of the distribution
transformer.
Total Distribution System Loss (kWh)
Specify the aggregate of energy loss in kWh for the entire Distribution System. This is the
difference between the Total Energy Input and the Total Energy Output.
Total Sub-Transmission Technical Loss (kWh)
Specify the total energy losses in kWh in the Sub-transmission System and
Distribution Substations (e.g. power transformers) of the Distribution Utility.
Total Feeder Technical Loss (kWh)
Specify the aggregate of Technical Losses in kWh associated with all the Primary and
Secondary Distribution Systems of the DU.
Total Non-Technical Loss (kWh)
Specify the aggregate of energy lost in kWh due to pilferage, meter reading errors, meter
tampering, and any Energy loss that is not related to the physical characteristics and
functions of the electric system.
ERC-DSLCAP-02:
Energy Input
Source ID
Specify the unique ID for the Energy Source or Input entry using up to 25 alphanumeric
characters along with dash (-) and underscore (_).
Source Description
Specify the description for the Source ID field using up to 100 alphanumeric characters
along with whitespace ( ), dash (-) and underscore (_).
Voltage Level (kV)
Specify the Voltage Level in kV of the Energy Source (e.g. 0.24, 34.5, 230, etc.).
81 | P a g e
Input Type
Specify the code from where the input energy was source using the following notations.
1 – from Transmission System,
2 – from DU Self-Generation,
3 – from Other Users,
4 – from Other Distribution System.
January (kWh)
Specify the Energy Input in kWh for the month of January for the particular Source ID.
February (kWh)
Specify the Energy Input in kWh for the month of February for the particular Source ID.
March (kWh)
Specify the Energy Input in kWh for the month of March for the particular Source ID.
April (kWh)
Specify the Energy Input in kWh for the month of April for the particular Source ID.
May (kWh)
Specify the Energy Input in kWh for the month of May for the particular Source ID.
June (kWh)
Specify the Energy Input in kWh for the month of June for the particular Source ID.
July (kWh)
Specify the Energy Input in kWh for the month of July for the particular Source ID.
August (kWh)
Specify the Energy Input in kWh for the month of August for the particular Source ID.
September (kWh)
Specify the Energy Input in kWh for the month of September for the particular Source
ID.
October (kWh)
Specify the Energy Input in kWh for the month of October for the particular Source ID.
November (kWh)
Specify the Energy Input in kWh for the month of November for the particular Source
ID.
December (kWh)
Specify the Energy Input in kWh for the month of December for the particular Source ID.
ERC-DSLCAP-03:
Energy Output
Customer Class ID
Specify the unique ID for the Customer Class entry using up to 25 alphanumeric
characters along with dash (-) and underscore (_).
Customer Class Description
Specify the description for the Customer Class ID field using up to 100 alphanumeric
characters along with whitespace ( ), dash (-) and underscore (_).
82 | P a g e
ERC Customer Class
Specify the Customer Class as defined by the ERC using the following values:
Table 10. ERC Customer Class Values
Value
RESIDENTIAL
LOW VOLTAGE
HIGHER VOLTAGE
DU Customer Type
Specify the unique ID for the Customer Type as defined by the Distribution Utility using
the following values:
Table 11. DU Customer Type Values
Value
RESIDENTIAL
COMMERCIAL
PUBLIC BUILDINGS
STREET LIGHTS
INDUSTRIAL
OTHERS
Voltage Level (kV)
Specify the Voltage Level in kV corresponding to the Customer Class (e.g. 0.24, 34.5,
230, etc.).
Note: The ERC Customer Class, DU Customer Type, and Voltage Level (kV) fields
together uniquely identifies and categorizes a Customer Class. Table 12 shows a sample
template.
Table 12. Sample Customer Class Template
Customer
Class ID
1
2
3
4
5
6
7
ERC Customer
Class
RESIDENTIAL
LOW VOLTAGE
LOW VOLTAGE
LOW VOLTAGE
LOW VOLTAGE
HIGHER VOLTAGE
HIGHER VOLTAGE
DU Customer Type
RESIDENTIAL
COMMERCIAL
PUBLIC BUILDINGS
INDUSTRIAL
STREET LIGHTS
COMMERCIAL
INDUSTRIAL
Voltage Level
(kV)
0.24
0.24
0.24
0.24
0.24
13.2
13.2
Output Type
Specify the code for which the output energy was delivered. Use the following notations:
1 – for Captive Customers,
2 – for Contestable Customers,
3 – for Customers under Supplier of Last Resort (SOLR),
4 – for DU Use.
January (kWh)
Specify the Energy Output in kWh for the month of January for the particular Customer
Class.
February (kWh)
Specify the Energy Output in kWh for the month of February for the particular Customer
Class.
83 | P a g e
March (kWh)
Specify the Energy Output in kWh for the month of March for the particular Customer
Class.
April (kWh)
Specify the Energy Output in kWh for the month of April for the particular Customer
Class.
May (kWh)
Specify the Energy Output in kWh for the month of May for the particular Customer
Class.
June (kWh)
Specify the Energy Output in kWh for the month of June for the particular Customer
Class.
July (kWh)
Specify the Energy Output in kWh for the month of July for the particular Customer
Class.
August (kWh)
Specify the Energy Output in kWh for the month of August for the particular Customer
Class.
September (kWh)
Specify the Energy Output in kWh for the month of September for the particular
Customer Class.
October (kWh)
Specify the Energy Output in kWh for the month of October for the particular Customer
Class.
November (kWh)
Specify the Energy Output in kWh for the month of November for the particular
Customer Class.
December (kWh)
Specify the Energy Output in kWh for the month of December for the particular
Customer Class.
ERC-DSLCAP-04:
Number of Customers
Customer Class ID
Specify the unique ID for the Customer Class entry using up to 25 alphanumeric
characters along with dash (-) and underscore (_).
Customer Class Description
Specify the description for the DU Customer Class ID field using up to 100 alphanumeric
characters along with whitespace ( ), dash (-) and underscore (_).
ERC Customer Class
Specify the Customer Class as defined by the ERC using the following values:
84 | P a g e
Table 13. ERC Customer Class Values
Value
RESIDENTIAL
LOW VOLTAGE
HIGHER VOLTAGE
DU Customer Type
Specify the unique ID for the Customer Type as defined by the Distribution Utility using
the following values:
Table 14. DU Customer Type Values
Value
RESIDENTIAL
COMMERCIAL
PUBLIC BUILDINGS
STREET LIGHTS
INDUSTRIAL
OTHERS
Voltage Level (kV)
Specify the Voltage Level in kV corresponding to the ERC Customer Class (e.g. 0.24,
34.5, 230, etc.).
Note: The ERC Customer Class, DU Customer Type, and Voltage Level (kV) fields
together uniquely identifies and categorizes a Customer Class. Table 15 shows a sample
template.
Table 15. Sample Customer Class Template
Customer
Class ID
1
2
3
4
5
6
7
ERC Customer
Class
RESIDENTIAL
LOW VOLTAGE
LOW VOLTAGE
LOW VOLTAGE
LOW VOLTAGE
HIGHER VOLTAGE
HIGHER VOLTAGE
DU Customer Type
RESIDENTIAL
COMMERCIAL
PUBLIC BUILDINGS
INDUSTRIAL
STREET LIGHTS
COMMERCIAL
INDUSTRIAL
Voltage Level
(kV)
0.24
0.24
0.24
0.24
0.24
13.2
13.2
January (Customers)
Specify the number of served customers for the month of January for the particular DU
Customer Class.
February (Customers)
Specify the number of served customers for the month of February for the particular DU
Customer Class.
March (Customers)
Specify the number of served customers for the month of March for the particular DU
Customer Class.
April (Customers)
Specify the number of served customers for the month of April for the particular DU
Customer Class.
85 | P a g e
May (Customers)
Specify the number of served customers for the month of May for the particular DU
Customer Class.
June (Customers)
Specify the number of served customers for the month of June for the particular DU
Customer Class.
July (Customers)
Specify the number of served customers for the month of July for the particular DU
Customer Class.
August (Customers)
Specify the number of served customers for the month of August for the particular DU
Customer Class.
September (Customers)
Specify the number of served customers for the month of September for the particular
DU Customer Class.
October (Customers)
Specify the number of served customers for the month of October for the particular DU
Customer Class.
November (Customers)
Specify the number of served customers for the month of November for the particular
DU Customer Class.
December (Customers)
Specify the number of served customers for the month of December for the particular
DU Customer Class.
ERC-DSLCAP-05:
Feeder List
This template must contain all existing feeders in the distribution network of the
Distribution Utility.
Feeder ID
Specify the unique ID for the feeder entry using up to 25 alphanumeric characters along
with dash (-) and underscore (_).
Feeder Description
Specify the description for the Feeder ID field using up to 100 alphanumeric characters
along with whitespace ( ), dash (-) and underscore (_).
Substation ID
Specify the Substation ID to where the specified Feeder ID field is connected. Use up to
25 alphanumeric characters along with dash (-) and underscore (_).
86 | P a g e
ERC-DSLCAP-06:
Substation List
This template must contain all existing substations in the distribution network of the
Distribution Utility.
Substation ID
Specify the unique ID for the substation entry using up to 25 alphanumeric characters
along with dash (-) and underscore (_).
Substation Description
Specify the description for the Substation ID field using up to 100 alphanumeric
characters along with whitespace ( ), dash (-) and underscore (_).
ERC-DSLCAP-07: System Loss CAPEX and OPEX
System Loss Reduction Project ID
Specify the unique ID for the System Loss Reduction Project entry using up to 25
alphanumeric characters along with dash (-) and underscore (_).
Project Description
Specify the description for the System Loss Reduction Project ID field using up to 100
alphanumeric characters along with whitespace ( ), dash (-) and underscore (_).
Expenditure Type
Specify the type of expenditure used for the System Loss Reduction Project using the
following notations:
Table 16. Expenditure Type Values
Value
CAPEX
OPEX
Description
Capital expenditure
Operational expenditure
Target Loss Component
Specify the particular loss component targeted for loss reduction. Use the following
notations to indicate the loss component:
Table 17. Target Loss Components Values
Value
STTL
SSTL
PDTL
DTTL
SDTL
PNTL
MNTL
OTL
ONTL
Description
Sub-Transmission Technical Loss
Substation Power Transformer Technical Loss
Primary Distribution System Technical Loss
Distribution Transformer Technical Loss
Secondary Distribution System Technical Loss
Non-Technical Loss due to Pilferage
Non-Technical Loss due to Meter/Meter Reading
Other Technical Loss
Other Non-Technical Loss
Project Cost (PhP)
Specify the total project cost in Philippine Peso for the particular System Loss Reduction
Project.
87 | P a g e
Start Month
Specify the month for the start of the particular System Loss Reduction Program. Use the
following notations:
Table 18. Month Values
Value
1
2
3
4
5
6
7
8
9
10
11
12
Description
Month of January
Month of February
Month of March
Month of April
Month of May
Month of June
Month of July
Month of August
Month of September
Month of October
Month of November
Month of December
Start Year
Specify the year for the start of the particular System Loss Reduction Program (Format:
YYYY; e.g. 2017).
End Month
Specify the month for the end of the particular System Loss Reduction Program. The
notations used follow that of Table 21.
End Year
Specify the year for the end of the particular System Loss Reduction Program (Format:
YYYY; e.g. 2017).
ERC-DSL-08:
Distribution Utility Load Data
Note: DU Load data shall be accomplished for January to December and submitted
annually.
Distribution Utility
Specify the abbreviated name of the Distribution System.
Month-Year
Specify the month/year for which the submitted data represents. (Format: e.g. August
2017)
Distribution Utility Load Type
Specify the type of DU load: DU Facility
Name of Facility
Describe the facility being applied for the approval of allowable Distribution Utility Use.
For substations and similar facilities, include the capacity of the facility.
Location of Facility
Specify the location or address of the facility.
88 | P a g e
Purpose of Facility
Describe the purpose or the justification why the facility is being applied for Allowable
Distribution Utility Use.
Space Area (sq. m.).
Specify the space area of the facility in square meters (sq. m.). For buildings, specify
the floor area. For substations and similar facilities, specify the land area.
Number of Users/Occupants
Specify the number of people occupying the facilities (e.g., 5 employees). Quantity
Specify the quantity (i.e., number of units) of connected electrical equipment or
appliance.
Connected Load (Description)
Describe the connected electrical equipment or appliance (e.g., 40W Fluorescent
lamp).
Use of Connected Load
Describe the usage or the services being provided by the electrical equipment or
appliance.
Rating (Watts)
Specify the ratings of connected electrical equipment or appliance in Watts.
Average Demand (kW)
Specify the Average Demand of the connected electrical load in kW. Note that electrical
appliances do not run at rated capacity (full load) at all times.
Average Duration (h)
Specify the average monthly duration of utilization of the connected electrical load in
hours. The average duration may be estimated by adding the number of hours of
usage in weekdays and in weekends in a typical 30-day month.
Average Monthly Consumption (kWh)
Multiply the Average Demand by the Average Duration to obtain the Average
Monthly Consumption of the connected electrical load.
Total Monthly Energy Consumption (kWh)
Add the Average Monthly Consumption of all connected electrical loads to obtain
the Total Monthly Energy Consumption of the Facility or Community Activity.
ERC-DSLCAP-09:
Actual Segregated DSL Data
Distribution Utility
Specify the abbreviated name of the Distribution System.
Year
Specify the year for which the submitted data represents. (Format: YYYY; e.g. 2018)
Total Energy Input (kWh)
Specify the monthly metered energy input in kWh to the entire Distribution System. This
is the energy delivered to the Distribution System by the Transmission System,
Embedded Generators, other Distribution Systems, and User Systems with generating
facilities.
89 | P a g e
Total Energy Output (kWh)
Specify the monthly Energy Output in kWh of the entire Distribution System. This is the
energy delivered to the Users of the Distribution System including the energy for
Distribution Utility Use.
Distribution Utility Use (kWh)
Specify the monthly aggregate of energy used for the proper operation of the distribution
system (e.g. for offices, administrative functions, etc.).
Total DSL (kWh/%)
Specify the monthly aggregate of energy loss in kWh and % for the entire Distribution
System. This is the difference between the Total Energy Input and the Total Energy
Output including DU Use.
Sub-Transmission and Substation Technical Loss (kWh/%)
Specify the monthly total energy losses in kWh and % in the Sub-Transmission System
and Substation of the Distribution Utility showing the actual/metered values and
corresponding simulated values.
Feeder Technical Loss (kWh/%)
Specify the monthly aggregate of Feeder Technical Loss in kWh and % associated with all
the Primary and Secondary Distribution Systems of the DU.
Non-Technical Loss (kWh/%)
Specify the monthly aggregate of energy lost in kWh and % due to pilferage, meter
reading errors, meter tampering, and any Energy loss that is not related to the physical
characteristics and functions of the electric system.
90 | P a g e
ANNEX C-1
Subtransmission and Substation Data DSLTemplates
ERC-DSLSUBT-00
ERC-DSLSUBT-01
ERC-DSLSUBT-02
ERC-DSLSUBT-03
ERC-DSLSUBT-04
ERC-DSLSUBT-05
ERC-DSLSUBT-06
ERC-DSLSUBT-07
ERC-DSLSUBT-08
ERC-DSLSUBT-09
ERC-DSLSUBT-10
ERC-DSLSUBT-11
ERC-DSLSUBT-12
ERC-DSLSUBT-13
ERC-DSLSUBT-14
ERC-DSLSUBT-15
ERC-DSLSUBT-16
DSL-SUBT Simulation Parameters
Billing Cycle Data
Metered Energy Input
Load Data
Load Energy Consumption Data
Load Curve Data
Bus Data
Subtransmission Line Data (Overhead)
Subtransmission Line Data (Underground)
Power Transformer Data (Two Winding Type)
Power Transformer Data (Three Winding Type)
Subtrans Svc Drop Data (Overhead)
Subtrans Svc Drop Data (Underground)
Voltage Regulator Data
Shunt Capacitor Data
Shunt Inductor Data
Series Inductor Data
ERC-DSLSUBT-00
Simulation Parameters
Sub-transmission Root Bus ID
Subtransmission Energy Input (kWh)
DU Use (kWh)
Power Mismatch
Base kVA
Maximum Iteration
0.0001
15
50
Percent PQ
Percent Z
100.00
0.00
Percent Loading
100.00
Source Voltage:
Hour 1
Hour 2
Hour 3
Hour 4
Hour 5
Hour 6
Hour 7
Hour 8
Hour 9
Hour 10
Hour 11
Hour 12
Hour 13
Hour 14
Hour 15
Hour 16
Hour 17
Hour 18
Hour 19
Hour 20
Hour 21
Hour 22
Hour 23
Hour 24
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
Simulation Parameters
ERC-DSLSUBT-01
Count
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Billing Cycle Data
Billing Period Code
Note: Add rows as necessary
Period Covered
Number of Days
Number of Hours
Billing Cycle Data 1/1
ERC-DSLSUBT-02
Count
Metered Energy Input
Meter ID
From
Bus ID
To
Bus ID
Metering Point Description
Metered Input (kWh)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
Note: Add rows as necessary
Metered Energy Input 1/1
ERC-DSLSUBT-03
Count
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Load Data
Load ID
Note: Add rows as necessary
Load Name
Load Type
Service Voltage
Phase
Load Data 1/1
ERC-DSLSUBT-04
Count
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Load Energy Consumption Data
Load ID
Note: Add rows as necessary
Billing Period Code
Energy Consumed (kWh)
Power Factor
Load Energy Consumption Data 1/1
ERC-DSLSUBT-05
Count
Load Curve Data
Load Curve ID
Load Type
Description
Hour 1
Hour 2
Hour 3
Hour 4
Hour 5
Hour 6
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Load Curve Data 1/3
ERC-DSLSUBT-05
Count
Hour 7
Load Curve Data
Hour 8
Hour 9
Hour 10
Hour 11
Hour 12
Hour 13
Hour 14
Hour 15
Hour 16
Hour 17
Hour 18
Hour 19
Hour 20
Hour 21
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Load Curve Data 2/3
ERC-DSLSUBT-05
Count
Hour 22
Load Curve Data
Hour 23
Hour 24
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Load Curve Data 3/3
ERC-DSLSUBT-06
Count
BUS DATA
Bus ID
Bus Description
Nominal Voltage (kV)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Bus Data 1/1
Subtransmission Line Data
(Overhead)
ERC-DSLSUBT-07
Count
Subtransmission Line
Segment ID
From
Bus ID
To
Bus ID
Phasing Configuration
No. of Ground Length Conductor
Wires
(meters)
Type
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Subtransmission Line-Overhead Data 1/3
Subtransmission Line Data
(Overhead)
ERC-DSLSUBT-07
Count
Conductor Unit Strands
Size
(C)
(C)
Bundled
Conductors
Bundled Conductor Ground Wire Ground Wire Unit Strands Spacing D12 Spacing D23 Spacing D13
Spacing (cm)
Type
Size
(GW) (GW)
(meters)
(meters)
(meters)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Subtransmission Line-Overhead Data 2/3
ERC-DSLSUBT-07
Count
Subtransmission Line Data
(Overhead)
Spacing D1g Spacing D2g Spacing D3g Spacing DC1-C2 Spacing Dgg Height H1 Height H2 Height H3 Height Hg Earth Resistivity
(meters)
(meters)
(meters)
(meters)
(meters) (meters) (meters) (meters)
(Ohm-meter)
(meters)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Subtransmission Line-Overhead Data 3/3
Subtransmission Line Data
(Underground/Submarine Cable)
ERC-DSLSUBT-08
Count
Subtransmission Line
Segment ID
From
Bus ID
To
Bus ID
Phasing
Length Conductor Conductor
(meters)
Type
Size
Unit
(C)
No. of Cores
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Subtransmission Line-Underground Data 1/2
Subtransmission Line Data
(Underground/Submarine Cable)
ERC-DSLSUBT-08
Count
Diameter under
Armor (mm)
Armor Wire
Diameter (mm)
Overall
Diameter (mm)
AC Resistance
(ohm/km)
Inductive Reactance
(ohm/km)
Capacitance
Earth Resistivity
(micro-farad/km)
(ohm-meter)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Subtransmission Line-Underground Data 2/2
Substation Power Transformer Data
(Two-Winding Type)
ERC-DSLSUBT-09
Count
Substation Power
Transformer ID
From
Primary Bus ID
To
Secondary Bus ID
Core
Structure
Method of
Cooling
kVA
Rating
(Primary)
kVA
Rating
(Secondary)
Max kVA
(Primary)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Power Transformer Data 2-Winding 1/3
Substation Power Transformer Data
(Two-Winding Type)
ERC-DSLSUBT-09
Count
Max kVA
(Secondary)
kV Rating
(Primary)
kV Rating Connection Connection Grounding Grounding Tap Changer Winding w/ Tap kV Setting
(Secondary) (Primary) (Secondary) (Primary) (Secondary)
Type
Auto LTC
(Primary)
Tap kV Setting
(Secondary)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Power Transformer Data 2-Winding 2/3
Substation Power Transformer Data
(Two-Winding Type)
ERC-DSLSUBT-09
Count
Impedance
(%Z)
X/R
Ratio
No-Load Loss Exciting Current
(kW)
(%)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Power Transformer Data 2-Winding 3/3
Substation Power Transformer Data
(Three-Winding Type)
ERC-DSLSUBT-10
Count
Substation Power
Transformer ID
From
Primary Bus ID
To
Secondary Bus ID
To
Tertiary Bus ID
Core
Method of kVA Rating
(Primary)
Structure Cooling
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Power Transformer Data 3 Winding 1/4
Substation Power Transformer Data
(Three-Winding Type)
ERC-DSLSUBT-10
Count
kVA Rating kVA Rating
(Secondary) (Tertiary)
Max kVA
(Primary)
Max kVA
(Secondary)
Max kVA
(Tertiary)
kV Rating kV Rating kV Rating Connection Connection Connection Grounding
(Primary) (Secondary) (Tertiary)
(Primary) (Secondary) (Tertiary)
(Primary)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Power Transformer Data 3 Winding 2/4
ERC-DSLSUBT-10
Count
Substation Power Transformer Data
(Three-Winding Type)
Grounding Grounding Tap Changer Winding w/ Tap kV Setting
(Secondary) (Tertiary)
(Primary)
Type
Auto LTC
Tap kV Setting
(Secondary)
Tap kV Setting Impedance X/R Ratio Impedance X/R Ratio
(Tertiary)
(%Zps)
(X/Rps)
(%Zpt)
(X/Rpt)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Power Transformer Data 3 Winding 3/4
ERC-DSLSUBT-10
Count
Substation Power Transformer Data
(Three-Winding Type)
Impedance X/R Ratio No-Load Loss Exciting Current
(%Zst)
(X/Rst)
(kW)
(%)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Power Transformer Data 3 Winding 4/4
Subtrans Svc Drop Data
(Overhead)
ERC-DSLSUBT-11
Count
Subtransmission Load
Service Drop ID
From
Bus ID
To
Load ID
Phasing
Configuration
System
Grounding Type
Length
(meters)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Subtrans Svc Drop Data-Overhead 1/3
Subtrans Svc Drop Data
(Overhead)
ERC-DSLSUBT-11
Count
Conductor
Type
Conductor
Size
Unit Strands Neutral Wire Neutral Wire Unit Strands Spacing D12 Spacing D23 Spacing D13 Spacing D1n Spacing D2n
(C)
(C)
Type
Size
(NW) (NW)
(meters)
(meters)
(meters)
(meters)
(meters)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Subtrans Svc Drop Data-Overhead 2/3
ERC-DSLSUBT-11
Count
Subtrans Svc Drop Data
(Overhead)
Spacing D3n Spacing DC1-C2 Height H1 Height H2 Height H3 Height Hn Earth Resistivity
(meters)
(meters) (meters) (meters) (meters)
(Ohm-meter)
(meters)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Subtrans Svc Drop Data-Overhead 3/3
Subtrans Svc Drop Data
(Underground Cable)
ERC-DSLSUBT-12
Count
Subtransmission Load
Service Drop ID
From
Bus ID
To
Load ID
Phasing
Configuration
System
Grounding Type
Length
(meters)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Subtrans Svc Drop Data-Underground 1/3
Subtrans Svc Drop Data
(Underground Cable)
ERC-DSLSUBT-12
Count
Conductor
Type
Conductor
Size
Unit Strands Neutral Wire
(C)
(C)
Type
Neutral Wire Unit Strands Spacing D12 Spacing D23 Spacing D13 Spacing D1n Spacing D2n
Size
(NW) (NW)
(meters)
(meters)
(meters)
(meters)
(meters)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Subtrans Svc Drop Data-Underground 2/3
ERC-DSLSUBT-12
Count
Subtrans Svc Drop Data
(Underground Cable)
Spacing D3n Spacing DC1-C2 Height H1 Height H2 Height H3 Height Hn Earth Resistivity
(meters)
(meters) (meters) (meters) (meters)
(Ohm-meter)
(meters)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Subtrans Svc Drop Data-Underground 3/3
ERC-DSLSUBT-13
Count
Voltage Regulator ID
Voltage Regulator Data
From
Bus ID
To
Bus ID
Regulated Bus ID
Phase Type
Phasing
Phase Sense
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
Note: Add rows as necessary
Voltage Regulator 1/3
ERC-DSLSUBT-13
Count
kVA Rating
Voltage Regulator Data
kV Rating
Target Voltage
(120V base)
Bandwidth
(120V base)
R-Setting
Phase A
R-Setting
Phase B
R-Setting
Phase C
X-Setting
Phase A
X-Setting
Phase B
X-Setting
Phase C
Primary Current
Rating (A)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
Note: Add rows as necessary
Voltage Regulator 2/3
ERC-DSLSUBT-13
Count
PT Ratio
Voltage Regulator Data
No-Load Loss Exciting
(kW)
Current (%)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
Note: Add rows as necessary
Voltage Regulator 3/3
ERC-DSLSUBT-14
Count
Shunt Capacitor ID
Shunt Capacitor Data
Bus Connected
(Bus ID)
Phase
Type
Phasing
kVAR Rating kVAR Rating kVAR Rating Power Loss
Voltage
Phase A
Phase B
Phase C
(Watts)
Rating (kV)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Shunt Capacitor 1/1
ERC-DSLSUBT-15
Count
Shunt Inductor ID
Shunt Inductor Data
Bus Connected
(Bus ID)
Phase
Type
Phasing
Voltage
Resistance
Resistance
Resistance
Rating (kV) Phase A (Ohms) Phase B (Ohms) Phase C (Ohms)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Shunt Inductor 1/2
ERC-DSLSUBT-15
Count
Shunt Inductor Data
Reactance
Reactance
Reactance
Phase A (Ohms) Phase B (Ohms) Phase C (Ohms)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Shunt Inductor 2/2
ERC-DSLSUBT-16
Count
Series Inductor Data
Series Inductor ID
From
Bus ID
To
Bus ID
Phase Type
Phasing
Voltage Rating
(kV)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Series Inductor 1/2
ERC-DSLSUBT-16
Count
Series Inductor Data
Resistance
Resistance
Resistance
Reactance Phase Reactance Phase Reactance Phase
Phase A (Ohms) Phase B (Ohms) Phase C (Ohms)
A (Ohms)
B (Ohms)
C (Ohms)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Series Inductor 2/2
ANNEX C-2
Feeder Data DSL Templates
ERC-DSL-00
ERC-DSL-01
ERC-DSL-02
ERC-DSL-03
ERC-DSL-04
ERC-DSL-05
ERC-DSL-06
ERC-DSL-07
ERC-DSL-08
ERC-DSL-09
ERC-DSL-10
ERC-DSL-11
ERC-DSL-12
ERC-DSL-13
ERC-DSL-14
ERC-DSL-15
ERC-DSL-16
Simulation Parameters
Customer Data
Billing Cycle Data
Customer Energy Consumption Data
Load Curve Data
Bus Data
Primary Distribution Line Data (Overhead)
Primary Distribution Line Data (Underground Cable)
Primary Customer Service Drop Data (Overhead)
Primary Customer Service Drop Data (Underground Cable)
Distribution Transformer Data
Secondary Distribution Line Data
Secondary Customer Service Drop Data
Voltage Regulator Data
Shunt Capacitor Data
Shunt Inductor Data
Series Inductor Data
ERC-DSL-00
Simulation Parameters
Feeder Root Bus ID
Feeder Energy Input (kWh)
DU Use (kWh)
Power Mismatch
Base kVA
Maximum Iteration
0.0001
15
50
Percent PQ
Percent Z
100.00
0.00
Percent Loading
100.00
Source Voltage:
Hour 1
Hour 2
Hour 3
Hour 4
Hour 5
Hour 6
Hour 7
Hour 8
Hour 9
Hour 10
Hour 11
Hour 12
Hour 13
Hour 14
Hour 15
Hour 16
Hour 17
Hour 18
Hour 19
Hour 20
Hour 21
Hour 22
Hour 23
Hour 24
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
1.00
Simulation Parameters
ERC-DSL-01
Count
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Customer Data
Customer ID
Note: Add rows as necessary
Customer Name
Customer Type
Service Voltage
Phase
Customer Data 1/1
ERC-DSL-02
Count
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Billing Cycle Data
Billing Period Code
Note: Add rows as necessary
Period Covered
Number of Days
Number of Hours
Billing Cycle Data 1/1
ERC-DSL-03
Count
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Customer Energy Consumption Data
Customer ID
Note: Add rows as necessary
Billing Period Code
Energy Consumed (kWh)
Power Factor
Customer Energy Consumption 1/1
ERC-DSL-04
Count
Load Curve Data
Load Curve ID
Customer Type
Description
Hour 1
Hour 2
Hour 3
Hour 4
Hour 5
Hour 6
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Load Curve 1/3
ERC-DSL-04
Count
Load Curve Data
Hour 7
Hour 8
Hour 9
Hour 10
Hour 11
Hour 12
Hour 13
Hour 14
Hour 15
Hour 16
Hour 17
Hour 18
Hour 19
Hour 20
Hour 21
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Load Curve 2/3
ERC-DSL-04
Count
Load Curve Data
Hour 22
Hour 23
Hour 24
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Load Curve 3/3
ERC-DSL-05
Count
BUS DATA
Bus ID
Bus Description
Nominal Voltage (kV)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Bus Data 1/1
Primary Distribution Line Data
(Overhead)
ERC-DSL-06
Count
Primary Distribution Line
Segment ID
From
Bus ID
To
Bus ID
Phasing
Configuration
System
Grounding Type
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Primary Distribution Line-Overhead 1/3
Primary Distribution Line Data
(Overhead)
ERC-DSL-06
Count
Length
(meters)
Conductor
Type
Conductor
Size
Unit Strands Neutral Wire Neutral Wire Unit Strands Spacing D12 Spacing D23 Spacing D13
(C)
(C)
Type
Size
(NW) (NW)
(meters)
(meters)
(meters)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Primary Distribution Line-Overhead 2/3
Primary Distribution Line Data
(Overhead)
ERC-DSL-06
Count
Spacing D1n Spacing D2n Spacing D3n Spacing DC1-C2 Height H1 Height H2 Height H3 Height Hn Earth Resistivity
(meters)
(meters)
(meters)
(meters) (meters) (meters) (meters)
(ohm-meter)
(meters)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Primary Distribution Line-Overhead 3/3
Primary Distribution Line Data
(Underground Cable)
ERC-DSL-07
Count
Primary Distribution Line
Segment ID
From
Bus ID
To
Bus ID
Phasing
Length
(meters)
Conductor Conductor
Type
Size
Unit (C)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Primary Distribution Line-Underground 1/2
Primary Distribution Line Data
(Underground Cable)
ERC-DSL-07
Count
No. of Cores
Diameter under
Armor (mm)
Armor Wire
Diameter (mm)
Overall
Diameter (mm)
AC Resistance
(ohm/km)
Inductive Reactance
(ohm/km)
Capacitance
(micro-farad/km)
Earth Resistivity
(ohm-meter)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Primary Distribution Line-Underground 2/2
Primary Customer Service Drop Data
(Overhead)
ERC-DSL-08
Count
Primary Customer
Service Drop ID
From
Bus ID
To
Bus ID
Phasing
Configuration
System Grounding
Type
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Primary Service Drop-Overhead 1/3
Primary Customer Service Drop Data
(Overhead)
ERC-DSL-08
Count
Length
(meters)
Conductor
Type
Conductor
Size
Unit (C)
Strands (C)
Neutral
Wire Type
Neutral Wire
Size
Unit (NW)
Strands
(NW)
Spacing D12 Spacing D23
(meters)
(meters)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Primary Service Drop-Overhead 2/3
Primary Customer Service Drop Data
(Overhead)
ERC-DSL-08
Count
Spacing D13 Spacing D1n Spacing D2n Spacing D3n Spacing DC1-C2 Height H1 Height H2 Height H3 Height Hn Earth Resistivity
(meters)
(meters)
(meters)
(meters)
(meters) (meters) (meters) (meters)
(ohm-meter)
(meters)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Primary Service Drop-Overhead 3/3
Primary Custormer Service Drop Data
(Underground Cable)
ERC-DSL-09
Count
Primary Customer Service
Drop ID
From
Bus ID
To
Bus ID
Phasing
Length
(meters)
Conductor Conductor
Type
Size
Unit (C)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
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Primary Customer Service Drop-Underground 1/2
Primary Custormer Service Drop Data
(Underground Cable)
ERC-DSL-09
Count
No. of Cores
Diameter under
Armor (mm)
Armor Wire
Diameter (mm)
Overall
Diameter (mm)
AC Resistance
(ohm/km)
Inductive Reactance
(ohm/km)
Capacitance
(micro-farad/km)
Earth Resistivity
(ohm-meter)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
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22
23
24
25
26
27
28
29
30
31
32
33
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35
Note: Add rows as necessary
Primary Customer Service Drop-Underground 2/2
ERC-DSL-10
Count
Distribution Transformer Data
Distribution Transformer ID
From
Primary Bus ID
To
Secondary Bus ID
Primary Secondary Installation
Phasing
Phasing
Type
No. DTs in
Bank
Connection
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
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35
Note: Add rows as necessary
Distribution Transformer Data 1/2
ERC-DSL-10
Count
Distribution Transformer Data
kVA Rating
Primary Voltage
Rating (kV)
Secondary Voltage
Rating (kV)
Primary Tap
Voltage (kV)
Secondary Tap
Voltage (kV)
%Z
X/R Ratio
No-Load Loss
Exciting
(kW)
Current (%)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Distribution Transformer Data 2/2
ERC-DSL-11
Count
Secondary Distribution
Line ID
Secondary Distribution Line Data
From
Bus ID
To
Bus ID
Phasing
Installation
Type
Length
(meters)
Conductor Conductor
Type
Size
Unit (C)
Strands
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
Note: Add rows as necessary
Secondary Distribution Line 1/1
ERC-DSL-12
Count
Secondary Customer
Service Drop ID
Secondary Customer Service Drop Data
From
Bus ID
To
Customer ID
Phasing
Installation
Type
Length-1
(meters)
Length-2
(meters)
Conductor Conductor
Type
Size
Unit
(C)
Strands
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
Note: Add rows as necessary
Secondary Service Drop 1/1
ERC-DSL-13
Count
Voltage Regulator Data
Voltage Regulator ID
From
Bus ID
To
Bus ID
Regulated Bus ID
Phase Type
Phasing
Phase Sense
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
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21
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23
24
25
26
27
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32
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34
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Voltage Regulator 1/3
ERC-DSL-13
Count
kVA Rating
Voltage Regulator Data
kV Rating
Target Voltage
(120V base)
Bandwidth
(120V base)
R-Setting
Phase A
R-Setting
Phase B
R-Setting
Phase C
X-Setting
Phase A
X-Setting
Phase B
X-Setting
Phase C
Primary Current
Rating (A)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
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22
23
24
25
26
27
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29
30
31
32
33
34
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Voltage Regulator 2/3
ERC-DSL-13
Count
PT Ratio
Voltage Regulator Data
No-Load Loss Exciting
(kW)
Current (%)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
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21
22
23
24
25
26
27
28
29
30
31
32
33
34
Note: Add rows as necessary
Voltage Regulator 3/3
ERC-DSL-14
Count
Shunt Capacitor Data
Shunt Capacitor ID
Bus Connected
(Bus ID)
Phase
Type
Phasing
kVAR Rating kVAR Rating kVAR Rating Power Loss
Voltage
Phase A
Phase B
Phase C
(Watts)
Rating (kV)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Shunt Capacitor 1/1
ERC-DSL-15
Count
Shunt Inductor Data
Shunt Inductor ID
Bus Connected
(Bus ID)
Phase
Type
Phasing
Voltage
Resistance
Resistance
Resistance
Rating (kV) Phase A (Ohms) Phase B (Ohms) Phase C (Ohms)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
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18
19
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24
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26
27
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30
31
32
33
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35
Note: Add rows as necessary
Shunt Inductor 1/2
ERC-DSL-15
Count
Shunt Inductor Data
Reactance
Reactance
Reactance
Phase A (Ohms) Phase B (Ohms) Phase C (Ohms)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
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19
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22
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24
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27
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30
31
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35
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Shunt Inductor 2/2
ERC-DSL-16
Count
Series Inductor Data
Series Inductor ID
From
Bus ID
To
Bus ID
Phase Type
Phasing
Voltage Rating
(kV)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
Note: Add rows as necessary
Series Inductor 1/2
ERC-DSL-16
Count
Series Inductor Data
Resistance
Resistance
Resistance
Reactance Phase Reactance Phase Reactance Phase
Phase A (Ohms) Phase B (Ohms) Phase C (Ohms)
A (Ohms)
B (Ohms)
C (Ohms)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
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17
18
19
20
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Series Inductor 2/2
ANNEX C-3
DU Annual Reportorial Requirement Template
ERC-DSLCAP-01
ERC-DSLCAP-02
ERC-DSLCAP-03
ERC-DSLCAP-04
ERC-DSLCAP-05
ERC-DSLCAP-06
ERC-DSLCAP-07
ERC-DSLCAP-08
ERC-DSLCAP-09
Annual DSL Summary
Energy Input Breakdown
Energy Ouput Breakdown
Number of Customers
Feeder List
Substation List
System Loss CAPEX and OPEX
DU Use Load Data
Actual Segregated DSL Data
ERC-DSLCAP-01
Annual DSL Summary
DISTRIBUTION UTILITY
YEAR
ENERGY
Total Energy Input (kWh)
Total Energy Output (kWh)
Distribution Utility Use (kWh)
NETWORK PARAMETER
Total Number of Substations
Total Number of Feeders
Total Number of Customers
Peak Demand (MW)
Primary Lines Total Circuit Length (meters)
Secondary Lines Total Circuit Length (meters)
DISTRIBUTION SYSTEM LOSS
Total System Loss (kWh)
Total Sub-Transmission and Substation Losses (kWh)
Total Feeder Technical Loss (kWh)
Total Non-Technical Loss (kWh)
Annual DSL Summary
ERC-DSLCAP-02
Source ID
Source Description
Note: Add rows as necessary
Energy Input
Voltage Level
(kV)
Input Type
January
(kWh)
February
(kWh)
March
(kWh)
April
(kWh)
May
(kWh)
June
(kWh)
July
(kWh)
August
(kWh)
Energy Input 1/2
ERC-DSLCAP-02
Source ID
September
(kWh)
Note: Add rows as necessary
Energy Input
October
(kWh)
November
(kWh)
December
(kWh)
Energy Input 2/2
ERC-DSLCAP-03
Customer
Class ID
Energy Output
Customer Class Description
Note: Add rows as necessary
ERC Customer Class
DU Customer Type
Voltage Level
(kV)
Output Type
January
(kWh)
February
(kWh)
March
(kWh)
Energy Output 1/2
ERC-DSLCAP-03
Customer
Class ID
Energy Output
April
(kWh)
Note: Add rows as necessary
May
(kWh)
June
(kWh)
July
(kWh)
August
(kWh)
September
(kWh)
October
(kWh)
November
(kWh)
December
(kWh)
Energy Output 2/2
ERC-DSLCAP-04
Customer
Class ID
Customer Class Description
Note: Add rows as necessary
Number of Customers
ERC Customer Class
DU Customer Type
Voltage Level (kV)
January
(No. of Customers)
February
(No. of Customers)
Number of Customers 1/3
ERC-DSLCAP-04
Customer
Class ID
March
(No. of Customers)
Note: Add rows as necessary
Number of Customers
April
(No. of Customers)
May
(No. of Customers)
June
(No. of Customers)
July
(No. of Customers)
August
(No. of Customers)
September
(No. of Customers)
Number of Customers 2/3
ERC-DSLCAP-04
Customer
Class ID
October
(No. of Customers)
Note: Add rows as necessary
Number of Customers
November
(No. of Customers)
December
(No. of Customers)
Number of Customers 3/3
ERC-DSLCAP-05
Feeder ID
Note: Add rows as necessary
Feeder List
Feeder Description
Substation ID
Feeder List 1/1
ERC-DSLCAP-06
Substation ID
Note: Add rows as necessary
Substation List
Substation Description
Substation List 1/1
ERC-DSLCAP-07
System Loss Reduction
Project ID
Note: Add rows as necessary
System Loss CAPEX and OPEX
Project Description
Expenditure Type
Target Loss
Component
Project Cost
(PhP)
Start
Month
Start Year
End
Month
End Year
System Loss CAPEX and OPEX 1/1
DU Use Load Data
(Distribution Utilility Facility)
ERC-DSLCAP-08
DU Use Load Type:
Name of Facility:
Location of Facility:
Purpose of Facility:
Space Area (sq. m.):
Number of Users/Occupants:
Count
Quantity
Distribution Utility:
Month-Year:
Connected Load
(Description)
Use of Connected Load
Rating
(Watts)
Average
Average
Ave. Monthly
Demand (kW) Duration (h) Consumption (kWh)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Total Monthly Energy Consumption (kWh)
Note: Accomplish this form for each Facility/Activity
Add rows as necessary
DU Use Load Data 1/1
ERC-DSLCAP-09
Actual Segregated DSL Data
DISTRIBUTION UTILITY:
YEAR:
Month
Energy Input (kWh)
(a)
Energy Output (kWh)
Delivered to Users
DU Use (kWh)
(b)
(c)
Total DSL (kWh)
(a) - (b) - (c)
Sub-Transmission and Substation Losses
(kWh)
Actual/Metered Values Simulated Values
January
February
March
April
May
June
July
August
September
October
November
December
Annual
Note: Add rows as necessary
Actual Segregated DSL 1/2
ERC-DSLCAP-09
Actual Segregated DSL Data
DISTRIBUTION UTILITY:
YEAR:
Month
Feeder Technical
Loss (kWh)
Non-Technical
Loss (kWh)
Sub-Transmission and Substation
Losses (%)
Actual/ Metered Values Simulated Values
Feeder Technical
Loss (%)
Non-Technical
Loss (%)
Total DSL (%)
January
February
March
April
May
June
July
August
September
October
November
December
Annual
Note: Add rows as necessary
Actual Segregated DSL 2/2
ANNEX “B”
METHODOLOGY ON THE DETERMINATION OF
DISTRIBUTION SYSTEM LOSS CAPS
This document presents a summary of the procedure taken to
determine the Distribution System Loss Caps. For this discussion, the
following components of Distribution System Losses were taken into
account:
1. Sub-Transmission and Substation Technical Loss;
2. Feeder Technical Loss; and
3. Non-Technical Loss.
I.
Sub-Transmission and Substation Technical Loss
Every Distribution Utility is expected to conduct power flow
simulation for the Sub-Transmission network including substation
equipment with substation loads.
Although technical losses are incurred in this section of the
Distribution System, substantial effort is already being conducted by DUs
to design and optimize this network of lines and power equipment to justify
capital expenditures. Hence, it is proposed that technical loss incurred in
this section may be passed on to consumers.
Due diligence in designing, analyzing, operating and developing this
section of the Distribution Network is expected and proper reporting to the
Regulator is likewise expected.
II.
Feeder Technical Loss
The most significant portion of Technical Loss in a Distribution
System is incurred in the feeder, specifically from the feeder through
Primary Distribution Lines, Distribution Transformers, Secondary
Distribution Lines and Service Drops. In addition, the DSL data of the
Distribution Utilities provided by the ERC allows detailed modeling and
power flow simulations on a per-feeder basis.
The objective of this part of the project is to benchmark feeder
performance in terms of Technical Loss incurred in the delivery of power.
However, in doing so, we posed the requirement that reasonable level of
losses will be incurred when the voltage quality meets the requirement of
the PDC, that is, that the voltages at all the delivery points meet the Long
Duration Voltage Variation criteria of being within ±10% of the nominal
voltage. To achieve this, using the DSL Data submitted to the ERC by all
Distribution Utilities, the following steps were taken:
A. For each feeder, initial power flow simulation was performed.
Network parameters such total energy for various voltage level
connections, total primary and secondary line lengths, total
transformer load and no-load losses, among others, were collected.
B. Voltage quality was assessed at all delivery points.
When the voltage at the delivery point falls outside the allowed
range, the delivery point was trimmed from the network; a
trimmed network was produced from the original network.
C. For each trimmed feeder, another power flow simulation was
performed.
New network parameters such as total energy for various voltage
level connections, total primary and secondary line lengths, total
load losses across lines and transformers, among others, were
collected.
D. After completing steps (A) to (C) for all feeders, statistical
modelling and benchmarking was performed.
1. After a few thousand feeder simulations, data on total technical
loss with corresponding network parameters were analyzed.
2. Multiple Linear Regression was performed to analyze which set
of network parameters can linearly predict Feeder Technical
Loss.
3. The following set of parameters were identified as good
predictors for Feeder Load Technical Loss, in kWh:
i. Energy Sales to HV Customers in kWh;
ii. The aggregate of Energy Sales to LV Customers and Energy
Sales to Residential Customers in kWh; and
iii. Total Secondary Line Lengths in km.
E. Feeder No-Load Technical Loss, that is, Distribution Transformer
No-load loss was presented better from the result of the power
flow simulation on the original (untrimmed) network.
It was identified that Peak Demand in MW is a good predictor of
Feeder No-Load Technical Loss.
2|Page
F. Taking together the results of steps D and E, the following set of
parameters when taken together were identified as good predictors
of Feeder Technical Loss in kWh:
i. Energy Sales to HV Customers, in kWh;
ii. The aggregate of Energy Sales to LV Customers and Energy
Sales to Residential Customers in kWh;
iii. Total Secondary Line Lengths in kilometer; and
iv. Peak Demand in MW.
The following linear approximation was obtained:
G. In order to further improve the prediction of Feeder Technical
Loss, Distribution Utilities were grouped according to Energy Sales
per Customer, as described in the Proposed Reforms to the Rules
for Setting Electric Cooperatives’ Wheeling Rates (RSEC-WR)
prepared by Castalla.
1. Multiple Linear Regression coefficients for each group were
generated. That is, coefficients A1, A2, A3, and A4 are now
generated for each group.
2. Table below shows the coefficients for estimating feeder
technical losses.
Group ID
Off-Grid DU
EC Group A
EC Group B
EC Group C
EC Group D
EC Group E
EC Group F
EC Group G
Private DU
A1
0.03124
0.04653
0.03352
0.01163
0.03058
0.02707
0.00943
0.02707
*0.00943
A2
0.02102
0.03906
0.02583
0.02469
0.03352
0.03653
0.03048
0.02016
*0.03048
A3
0.01922
0.00742
0.02934
0.01603
0.01870
0.00787
0.02150
0.05179
*0.02150
A4
0.01707
0.01315
0.00936
0.01107
0.00809
0.00950
0.00507
0.00608
*0.00507
* In the absence of feeder data, coefficients for Group F were used for the
Private DU Group.
H. Having Equation #1 with a unique set of coefficients for each
group, and using total Network Parameters for every Distribution
Utility (DU), an estimate Feeder Technical Loss, both in kWh and
percent of Energy Input, was computed for each DU.
3|Page
I. It is also needed to adjust the values to incorporate the Technical
Loss due to Non-Technical Loss. This can be described by the
following equation:
J. Based on the distribution of estimate Feeder Technical Loss,
among DUs of the same groups, Feeder Technical Loss caps were
set.
K. Across groups with the same Feeder Technical Loss caps, clusters
of DUs were identified.
Feeder Technical
Loss Cap
Cluster 1 (EC)
7.50 %
Cluster 2 (EC)
5.75 %
Cluster 3 (EC)
3.75 %
Cluster 4
3.50 %
(Private DU)
Cluster ID
Non-Technical
Loss Cap
4.50 %
4.50 %
4.50 %
12.00 % + DSLSS+ST
10.25% + DSLSS+ST
8.25% + DSLSS+ST
1.25 %
4.75 % + DSLSS+ST
Total DSL Cap
III. Non-Technical Loss
Distribution Utilities have been required to submit summary of NonTechnical Loss in an annual basis. Aside from this, no other set of data
were collected from Distribution Utilities that will allow analysis of NonTechnical Loss.
For now, Non-Technical Loss caps were set based on the average
Non-Technical Loss reported by Distribution Utilities from 2011 to 2015.
The averages were significantly different between Electric Cooperatives and
Private DUs. Hence, separate caps were set for these two types of DU.
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