A Resolution Adopting the ERC Rules for Setting the Distribution System Loss Cap and Establishing Performance Incentive Scheme for Distribution Efficiency

December 5, 2017

ERC RESOLUTION NO. 20-17

A RESOLUTION ADOPTING THE ERC RULES FOR SETTING THE DISTRIBUTION SYSTEM LOSS CAP AND ESTABLISHING PERFORMANCE INCENTIVE SCHEME FOR DISTRIBUTION EFFICIENCY

WHEREAS, Section 43 (f) of Republic Act No. 9136, otherwise known as the Electric Power Industry Reform Act of 2001 (EPIRA) 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, said engagement required PowerSolv, Inc. to: 1) come up with a new distribution system loss caps (technical and non-technical losses) including incentive scheme for system 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 non-technical 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);

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 in 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 Resolution;

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.

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, December 5, 2017.

(SGD.) AGNES VST DEVANADERAChairperson and CEO

(SGD.) ALFREDO J. NONCommissioner

(SGD.) GLORIA VICTORIA C. YAP-TARUCCommissioner

(SGD.) JOSEFINA PATRICIA A. MAGPALE-ASIRITCommissioner

(SGD.) GERONIMO D. STA. ANACommissioner

ANNEXA

Rules for Setting the Distribution System Loss Cap and Establishing Performance Incentive Scheme for Distribution Efficiency

Final Rules

December 5, 2017

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:

"x x x. 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. x x x"

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 Section 10 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.

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.
Connection Assets	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.
Contestable Customer	A Customer who has the choice of supplier of electricity, as determined by the ERC in accordance with EPIRA.
Customer	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.
Distribution Charge	The charges for distribution, supply, metering and other related charge and adjustments.
Distribution Feeder Loss	This is the sum of Feeder Technical Loss and Non-Technical Loss.
Distribution System	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 System Loss (DSL)	The electric Energy Input minus the electric Energy Output for a specified billing period or set of billing periods.
Distribution Utility (DU)	Any Electric Cooperative, private corporation, 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 Utility Use	The aggregate of energy used for the proper 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 Cooperative (EC)	A Distribution Utility organized pursuant to Presidential Decree No. 269, as amended, or otherwise provided in EPIRA.
Embedded Generators	Generating Units that is indirectly connected to 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 Commission (ERC)	The independent quasi-judicial regulatory body created under EPIRA.
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.
Feeder Technical Loss	The sum of the Technical Losses associated with the Primary Distribution System and the Secondary Distribution System.
Generating Plant	A facility consisting of one or more Generating Units.
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.
Grid	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.
Higher Voltage Customer (HV or MV Customer)	A Customer that is connected to and served through the Sub-Transmission System or the Primary Distribution System.
Isolated 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.
Low Voltage Customer (LV Customer)	A Customer that is not a Residential Customer and is connected to and served through the Secondary Distribution System.
Non-Technical Loss (NTL)	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.
Off-Grid EC	An Electric Cooperative that operates an Isolated Distribution System.
On-Grid EC	An Electric Cooperative that operates a Distribution System that is connected to any one of the national Transmission Systems in Luzon, Visayas, or Mindanao.
Peak Power Demand	The maximum value of power, measured in MW, required by the Distribution Utility for a specific billing period or set of billing periods.
Performance Incentive Schemes (PIS)	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.
Philippine Distribution Code (PDC)	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.
Primary Distribution System	A portion of the Distribution System delineated by the secondary side of the Substation transformer and the primary side of all Distribution transformers.
Private Distribution Utility (PDU)	A Distribution Utility that is operated by a private corporation.
Reference Distribution Network	An idealized version of the Distribution System, formulated as prescribed in Section 4 of this Rules.
Regulatory Period	A period of time over which the rates of the Distribution Utility is defined under a set of rules issued by the ERC.
Republic Act No. 7832	The law otherwise known as the Anti-electricity and Electric Transmission Lines/Materials Pilferage Act of 1994.
Residential Customer	A Customer that is residential in nature and connected to and served through the Secondary Distribution System.
Secondary Distribution System	A portion of the Distribution System that is at the secondary side of a Distribution transformer.
Secondary Line	A Distribution line connected at the Secondary Distribution System.
Sub-Transmission and Substation Loss	This is the sum of Sub-Transmission System and Substation Technical Losses and Non-Technical Loss.
Sub-Transmission and Substation Technical Loss	The sum of the Technical Losses associated with the Sub-Transmission System and Distribution substations.
Sub-Transmission System	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.
System	A group of components connected or associated in a fixed configuration to perform a specific function.
System Loss Charge	The charge representing recovery of the cost of power due to Distribution System Loss.
System Loss Rate	The rate determined in accordance with ERC Resolution No. 16, Series of 2009 and any amendments thereto.
Technical Loss (TL)	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.
Three-Phase Power Flow	An analytical tool that simulates the power flows in an unbalanced three-phase Distribution System.
Transmission System	Has the same definition as "Grid."
User	A person or entity that uses the Distribution System and related distribution facilities.
User System	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.

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

 

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.

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 (DSL_ST+SS); and

b. The actual sum of Non-Technical Loss (NTL) and Feeder Technical Loss (TL_fdr), or the Distribution Feeder Loss cap (DSL_fdr,cap), whichever is lower.

SL_{SysLossCharge} = DSL_ST+SS + Min {(TL_fdr + NTL), DSL_fdr,cap} (Equation 2.1)

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 (DSL_ST+SS) shall be computed using actual metered quantities. It shall be set to 0.00 for non-submission of the Monthly Sub-Transmission and Substation DSL Data by the DU.

2.4.4 In the absence of Metered DSL_ST+SS data submitted by the DU, the Distribution Feeder Loss (DSL_fdr) 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 Non-Technical 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.

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,

SDSLfdr,t	=	Performance incentive for Distribution Feeder Loss for year t;
WDSLfdr	=	Weight assigned to Distribution Feeder Loss performance; and
PerfDSLfdr,t-1	=	Performance Assessment Factor for Distribution Feeder Loss in the previous year.

 

3.2.4 Based on the value of the actual total DSL_fdr and its relationship with the various thresholds in the PIS reward structure for ECs, the value of the Performance Assessment Factor (Perf_DSLfdr,t-1) 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.

Table 6. Performance Assessment Factor Computation for ECs

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 (S_t) shall be computed in the following manner:

Where,
SDSLfdr,t	=	Performance incentive for Distribution Feeder Loss for year t;
WDSLfdr	=	Weight assigned to Distribution Feeder Loss performance; and
PerfDSLfdr,t-1	=	Performance Assessment Factor for Distribution Feeder Loss in the previous year.

3.3.4 Based on the value of the actual total DSL_fdr and its relationship with the various thresholds in the PIS structure for Private DUs, the value of the Performance Assessment Factor (Perf_DSLfdr,t-1) 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

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.

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.

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.

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 ERC-prescribed 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. Total Energy Input, in kWh;

b. Total Energy Output, in kWh;

c. Distribution Utility Use, in kWh;

d. Total Number of Substations;

e. Total Number of Feeders;

f. Total Number of Customers;

g. Peak Demand, in MW;

h. Total Circuit Length of Primary Lines, in meters;

i. Total Circuit Length of Secondary Lines, in meters;

j. Total System Loss, in kWh;

k. Sub-Transmission and Substation Loss, in kWh;

l. Feeder Technical Loss, in kWh;

m. Non-Technical Loss, in kWh;

n. Total Energy Output for each Customer class, in kWh (e.g., HV Customers, LV Customers, and Residential Customers);

o. Total Number of Customers per Customer class, in kWh (e.g., HV Customers, LV Customers, and Residential Customers);

p. List of CAPEX and OPEX programs related to the Technical Loss and Non-Technical Loss reduction programs;

q. DU Use Load Data; and

r. 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.

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.

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. Sub-Transmission and Substation Technical Loss;

b. Feeder Technical Loss; and

c. 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. Sub-Transmission Lines;

b. Substation Power Transformers;

c. Primary Distribution Lines;

d. Voltage Regulators;

e. Capacitors;

f. Inductors or Reactors;

g. Distribution Transformers;

h. Secondary Distribution Lines;

i. Service Drops; and

j. Metering Equipment and Instrument Transformers;

k. 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.

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

Total Distribution System Loss

= SEnergy delivered by the Transmission System

+ SEnergy delivered by Embedded Generators

+ SEnergy delivered by other Distribution Systems

+ SEnergy delivered by User Systems with Generating Units

- SEnergy delivered to the Users of the Distribution System

- Distribution Utility Use

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:

a. Distribution Substations;

b. Offices of the Distribution Utility;

c. Warehouses and Workshops of the Distribution Utility; and

d. 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

Distribution Utility Use

= SEnergy Consumed by Distribution Substations

+ SEnergy Consumed by Offices of the Distribution Utility

+ SEnergy Consumed by Warehouses and Workshops of the DU

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

Subtransmission and Substation Technical Loss

= SHourly Load Losses in Subtranmission Lines

+ SHourly Load Losses in Substation Transformers

+ SHourly No-Load Losses in Substation Transformers

+ SHourly Load Losses in Subtransmission Service Drops

+ SHourly Load Losses in Subtransmission Voltage Regulators

+ SHourly Load Losses in Subtransmission Capacitors

+ SHourly Load Losses in Subtransmission Inductors

+ SLosses in Subtransmission Metering Equipment

+ SLosses in other Subtransmission Equipment

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

Feeder Technical Loss

= SHourly Load Losses in Primary Distribution Lines

+ SHourly Load Losses of Primary Service Drops

+ SHourly Load Losses in Distribution Transformers

+ SHourly No-Load Losses in Distribution Transformers

+ SHourly Load Losses in Secondary Distribution Lines

+ SHourly Load Losses in Secondary Service Drops

+ SHourly Load Losses in Voltage Regulators

+ SHourly Load Losses in Capacitors

+ SHourly Load Losses in Inductors

+ SLosses in Metering Equipment

+ SLosses in other Distribution Equipment

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:

Equations A.5. Metering Equipment Loss

Potential Transformer Loss

= S_iPower Loss in PT_i x Number of PT_i

x Number of Operating Hours

Current Transformer Loss

= S_jPower Loss in CT_j x Number of CT_j

x Number of Operating Hours

Electric Meter Potential Coil Loss

= S_mPower Loss in Electric Meter Potential Coil_m

x Number of Electric Meters_m

x Number of Operating Hours

Electric Meter Current Coil Loss

= S_nPower Loss in Electric Meter Current Coil_n

x Number of Electric Meters_n

x Number of Operating Hours

Losses in Metering Equipment

= Potential Transformer Loss

+ Current Transformer Loss

+ Electric Meter Potential Coil Loss

+ Electric Meter Current Coil Loss

The Metering Equipment Loss for customers connected through the sub-transmission 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 Electric Energy Input less the total Technical Loss for the Billing Period. The total Technical Loss shall be calculated as the sum of the Sub-Transmission and Substation Technical Loss and the Feeder Technical Loss.

In equation form, the Non-Technical Loss shall be computed as follows:

Equations A.6. Non-Technical Loss

Non-Technical Loss

= Total Distribution System Loss

- Technical Loss in Subtransmission and Substations

- Technical Loss in Distribution Feeders

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 three-phase 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 (p) equivalent network with the corresponding self- and mutual impedances of the phase and ground conductors, as shown in Figure A-2.

Figure A-2. Equivalent p-Network of Distribution Lines

The series self- and mutual impedances of the conductors are given by the Carson equations:

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,

 

Hxx =	Distance of conductor x to its image;
Hxy =	Distance of conductor x to the image of conductor y;
rx =	Radius of conductor x;
Dxy =	Distance between conductors x and y (xy can be ab, bc, or ca); and
e =	Permittivity of the region surrounding the conductors.

If conductor w represents the overhead ground wire or grounded neutral wire, then v_w = 0, 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 X_c, which can be obtained using the following equation:

Where,

w =	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.

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

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

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 P_t for time t is obtained from the per unit (p.u.) demand p_tdivided by the total area under the normalized load curve.

Figure A-8. Converting Monthly Customer Energy Bill to Hourly Power Demand

The power factor (pf_t) is used to compute for the hourly reactive power demand (Q_t) 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

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 Use that 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) ERC-DSL-02: Customer Data;

b) ERC-DSL-03: Billing Cycle Data;

c) ERC-DSL-04: Customer Energy Consumption Data; and

d) ERC-DSL-05: 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) Bus Data;

b) Sub-Transmission Line Data;

c) Substation Power Transformer Data;

d) Primary Distribution Line Data;

e) Distribution Transformer Data;

f) Secondary Distribution Line Data;

g) Primary and Secondary Customer Service Drop Data;

h) Voltage Regulator Data;

i) Shunt Capacitor Data;

j) Shunt Inductor Data; and

k) 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 or more distribution system element

 

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

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 (%)

 

Table 10. Substation Power Transformer Data — Three Winding

Substation Power Transformer ID

Connection Points Identification

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

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

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

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

 

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

 

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 Sub-transmission 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.

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 Sub-transmission Network. (Typical value for Source Voltage per hour is 1.0)

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.

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.

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

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:

A1/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

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.

Figure 5. Conductor Spacing

Spacing D1g (meters)

Specify the distance in meters between Conductor 1 and the Ground Wire. For Sub-Transmission 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 Sub-Transmission 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 Sub-Transmission 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

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.

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.

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.

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. HTcADC

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

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.

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.

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

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.

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 Sub-Transmission 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.

Phasing shall be specified using the following conventions:

a) ABCN or ABC if Phases A, B, and C correspond to conductors 1, 2, and 3 respectively;

b) ACBN or ACB if Phases A, C, and B correspond to conductors 1, 2, and 3 respectively;

c) BCAN or BCA if Phases B, C, and A correspond to conductors 1, 2, and 3 respectively;

d) BACN or BAC if Phases B, A, and C correspond to conductors 1, 2, and 3 respectively;

e) CABN or CAB if Phases C, A, and B correspond to conductors 1, 2, and 3 respectively;

f) CBAN or CBA if Phases C, B, and A correspond to conductors 1, 2, and 3 respectively;

g) ABN or AB if Phases A and B correspond to conductors 1 and 2 respectively;

h) BAN or BA if Phases B and A correspond to conductors 1 and 2 respectively;

i) BCN or BC if Phases B and C correspond to conductors 1 and 2 respectively;

j) CBN or CB if Phases C and B correspond to conductors 1 and 2 respectively;

k) CAN or CA if Phases C and A correspond to conductors 1 and 2 respectively;

l) ACN or AC if Phases A and C correspond to conductors 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.

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) For ABCN and ABC: D12 is the distance between Phase A and Phase B;

b) For ACBN and ACB: D12 is the distance between Phase A and Phase C;

c) For BCAN and BCA: D12 is the distance between Phase B and Phase C;

d) For BACN and BAC: D12 is the distance between Phase B and Phase A;

e) For CABN and CAB: D12 is the distance between Phase C and Phase A;

f) For CBAN and CBA: D12 is the distance between Phase C and Phase B;

g) For ABN and AB: D12 is the distance between Phase A and Phase B;

h) For BAN and BA: D12 is the distance between Phase B and Phase A;

i) For BCN and BC: D12 is the distance between Phase B and Phase C;

j) For CBN and CB: D12 is the distance between Phase C and Phase B;

k) For CAN and CA: D12 is the distance between Phase C and Phase A;

l) For ACN and AC: D12 is the distance between Phase A and Phase C;

m) For AN: D12 = 0;

n) For BN: D12 = 0; and

o) 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) For ABCN and ABC: D23 is the distance between Phase A and Phase B;

b) For ACBN and ACB: D23 is the distance between Phase A and Phase C;

c) For BCAN and BCA: D23 is the distance between Phase B and Phase C;

d) For BACN and BAC: D23 is the distance between Phase B and Phase A;

e) For CABN and CAB: D23 is the distance between Phase C and Phase A;

f) For CBAN and CBA: D23 is the distance between Phase C and Phase B;

g) For ABN and AB: D23 is the distance between Phase A and Phase B;

h) For BAN and BA: D23 is the distance between Phase B and Phase A;

i) For BCN and BC: D23 is the distance between Phase B and Phase C;

j) For CBN and CB: D23 is the distance between Phase C and Phase B;

k) For CAN and CA: D23 is the distance between Phase C and Phase A;

l) For ACN and AC: D23 is the distance between Phase A and Phase C;

m) For AN: D23 = 0;

n) For BN: D23 = 0; and

o) 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) For ABCN and ABC: D13 is the distance between Phase A and Phase B;

b) For ACBN and ACB: D13 is the distance between Phase A and Phase C;

c) For BCAN and BCA: D13 is the distance between Phase B and Phase C;

d) For BACN and BAC: D13 is the distance between Phase B and Phase A;

e) For CABN and CAB: D13 is the distance between Phase C and Phase A;

f) For CBAN and CBA: D13 is the distance between Phase C and Phase B;

g) For ABN and AB: D13 is the distance between Phase A and Phase B;

h) For BAN and BA: D13 is the distance between Phase B and Phase A;

i) For BCN and BC: D13 is the distance between Phase B and Phase C;

j) For CBN and CB: D13 is the distance between Phase C and Phase B;

k) For CAN and CA: D13 is the distance between Phase C and Phase A;

l) For ACN and AC: D13 is the distance between Phase A and Phase C;

m) For AN: D13 = 0;

n) For BN: D13 = 0;

o) 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.

ERC-DSLSUBT-12: Subtrans Svc Drop-Underground

Except for the following fields, the rest of the field names for the Subtrans Svc Drop-Underground 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 — Single phase

2 — Two single phase

3 — Three-phase, gang operated

4 — 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 — if Phase A

B — if Phase B

C — 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.

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 — Single-phase Shunt Capacitor

2 — Two (2) single-phase Shunt Capacitors

3 — Three-phase Shunt Capacitor

4 — 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 — Single-phase Shunt Inductor

2 — Two (2) Single-phase Shunt Inductors

3 — Three-phase Shunt Inductor

4 — 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 — One (1) Single-phase Series Inductor

2 — Two (2) single-phase Series Inductors

3 — One (1) Three-phase Series Inductor

4 — 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 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.

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.

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)

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.

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).

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.).

Connect ion 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 conductors 1, 2 and 3, respectively;

b) ACBN or ACB if Phases A, C and B correspond to conductors 1, 2 and 3, respectively;

c) BCAN or BCA if Phases B, C and A correspond to conductors 1, 2 and 3, respectively;

d) BACN or BAC if Phases B, A and C correspond to conductors 1, 2 and 3, respectively;

e) CABN or CAB if Phases C, A and B correspond to conductors 1, 2 and 3, respectively;

f) CBAN or CBA if Phases C, B and A correspond to conductors 1, 2 and 3, respectively;

g) ABN or AB if Phases A and B correspond to conductors 1 and 2, respectively;

h) BAN or BA if Phases B and A correspond to conductors 1 and 2, respectively;

i) BCN or BC if Phases B and C correspond to conductors 1 and 2, respectively;

j) CBN or CB if Phases C and B correspond to conductors 1 and 2, respectively;

k) CAN or CA if Phases C and A correspond to conductors 1 and 2, respectively;

l) ACN or AC if Phases A and C correspond to conductors 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.

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.

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) For ABCN and ABC: D12 is the distance between Phase A and Phase B;

b) For ACBN or ACB: D12 is the distance between Phase A and Phase C;

c) For BCAN or BCA: D12 is the distance between Phase B and Phase C;

d) For BACN or ABC: D12 is the distance between Phase B and Phase A;

e) For CABN or CAB: D12 is the distance between Phase C and Phase A;

f) For CBA or CBA: D12 is the distance between Phase C and Phase B;

g) For ABN or AB: D12 is the distance between Phase A and Phase B;

h) For BAN or BA: D12 is the distance between Phase B and Phase A;

i) For BCN or BC: D12 is the distance between Phase B and Phase C;

j) For CBN or CB: D12 is the distance between Phase C and Phase B;

k) For CAN or CA: D12 is the distance between Phase A and Phase B;

l) For ACN or AC: D12 is the distance between Phase A and Phase C;

m) For AN: D12 = 0;

n) For BN: D12 = 0; and

o) 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) For ABCN and ABC: D23 is the distance between Phase B and Phase C;

b) For ACBN or ACB: D23 is the distance between Phase C and Phase B;

c) For BCAN or BCA: D23 is the distance between Phase C and Phase A;

d) For BACN or ABC: D23 is the distance between Phase A and Phase C;

e) For CABN or CAB: D23 is the distance between Phase A and Phase B;

f) For CBA or CBA: D23 is the distance between Phase B and Phase A;

g) For ABN or AB: D23 = 0;

h) For BAN or BA: D23 = 0;

i) For BCN or BC: D23 = 0;

j) For CBN or CB: D23 = 0;

k) For CAN or CA; D23 = 0;

l) For ACN or AC; D23 = 0;

m) For AN: D23 = 0;

n) For BN: D23 = 0;

o) 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) For ABCN and ABC: D13 is the distance between Phase A and Phase C;

b) For ACBN or ACB: D13 is the distance between Phase A and Phase B;

c) For BCAN or BCA: D13 is the distance between Phase B and Phase A;

d) For BACN or ABC: D13 is the distance between Phase B and Phase C;

e) For CABN or CAB: D13 is the distance between Phase C and Phase B;

f) For CBA or CBA: D13 is the distance between Phase C and Phase A;

g) For ABN or AB: D13 = 0;

h) For BAN or BA: D13 = 0;

i) For BCN or BC: D13 = 0;

j) For CBN or CB: D13 = 0;

k) For CAN or CA: D13 = 0;

l) For ACN or AC: D13 = 0;

m) For AN: D13 = 0;

n) For BN: D13 = 0; and

o) 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 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.

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 — One (1) Single-phase Distribution Transformer

2 — Two (2) Single-phase Distribution Transformers

3 — One (1) Three-phase Distribution Transformer

4 — Three (3) Single-phase Distribution Transformers

Connection

Specify the connection of the Distribution Transformer:

1 — Single Phase

2 — Delta-Delta

3 — Delta-WyeGrnd

4 — Delta-Wye

5 — WyeGrnd-WyeGrnd

6 — WyeGrnd-Wye

7 — Wye-WyeGrnd

8 — Wye-Wye

9 — WyeGrnd-Delta

10 — Wye-Delta

11 — Open Delta-Open Delta

12 — 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.

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.

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.

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 — Single phase

2 — Two single phase

3 — Three-phase, gang operated

4 — 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 — if Phase A

B — if Phase B

C — 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.

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.

Phase Type

Specify the construction type of Shunt Capacitor:

1 — Single-phase Shunt Capacitor

2 — Two (2) single-phase Shunt Capacitors

3 — Three-phase Shunt Capacitor

4 — 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 — Single-phase Shunt Inductor

2 — Two (2) Single-phase Shunt Inductors

3 — Three-phase Shunt Inductor

4 — 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.

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 — One (1) Single-phase Series Inductor

2 — Two (2) single-phase Series Inductors

3 — One (1) Three-phase Series Inductor

4 — 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 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;

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.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) ERC-DSLCAP-01: Annual DSL Summary

b) ERC-DSLCAP-02: Energy Input

c) ERC-DSLCAP-03: Energy Output

d) ERC-DSLCAP-04: Number of Customers

e) ERC-DSLCAP-05: Distribution Feeder List

f) ERC-DSLCAP-06: Distribution Substation List

g) ERC-DSLCAP-07: DSL CAPEX & OPEX

h) ERC-DSLCAP-08: DU Use Load Data

i) ERC-DSLCAP-09: 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.

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.).

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 (_).

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	ERC Customer Class	DU Customer Type	Voltage Level (kV)
1	RESIDENTIAL	RESIDENTIAL	0.24
2	LOW VOLTAGE	COMMERCIAL	0.24
3	LOW VOLTAGE	PUBLIC BUILDINGS	0.24
4	LOW VOLTAGE	INDUSTRIAL	0.24
5	LOW VOLTAGE	STREET LIGHTS	0.24
6	HIGHER VOLTAGE	COMMERCIAL	13.2
7	HIGHER VOLTAGE	INDUSTRIAL	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.

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:

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	ERC Customer Class	DU Customer Type	Voltage Level (kV)
1	RESIDENTIAL	RESIDENTIAL	0.24
2	LOW VOLTAGE	COMMERCIAL	0.24
3	LOW VOLTAGE	PUBLIC BUILDINGS	0.24
4	LOW VOLTAGE	INDUSTRIAL	0.24
5	LOW VOLTAGE	STREET LIGHTS	0.24
6	HIGHER VOLTAGE	COMMERCIAL	13.2
7	HIGHER VOLTAGE	INDUSTRIAL	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.

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 (_).

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	Description
CAPEX	Capital expenditure
OPEX	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	Description
STTL	Sub-Transmission Technical Loss
SSTL	Substation Power Transformer Technical Loss
PDTL	Primary Distribution System Technical Loss
DTTL	Distribution Transformer Technical Loss
SDTL	Secondary Distribution System Technical Loss
PNTL	Non-Technical Loss due to Pilferage
MNTL	Non-Technical Loss due to Meter/Meter Reading
OTL	Other Technical Loss
ONTL	Other Non-Technical Loss

Project Cost (PhP)

Specify the total project cost in Philippine Peso for the particular System Loss Reduction Project.

Start Month

Specify the month for the start of the particular System Loss Reduction Program. Use the following notations:

Table 18. Month Values

Value	Description
1	Month of January
2	Month of February
3	Month of March
4	Month of April
5	Month of May
6	Month of June
7	Month of July
8	Month of August
9	Month of September
10	Month of October
11	Month of November
12	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.

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.

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.

Annexes C available upon request.

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.

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	A1	A2	A3	A4
Off-Grid DU	0.03124	0.02102	0.01922	0.01707
EC Group A	0.04653	0.03906	0.00742	0.01315
EC Group B	0.03352	0.02583	0.02934	0.00936
EC Group C	0.01163	0.02469	0.01603	0.01107
EC Group D	0.03058	0.03352	0.01870	0.00809
EC Group E	0.02707	0.03653	0.00787	0.00950
EC Group F	0.00943	0.03048	0.02150	0.00507
EC Group G	0.02707	0.02016	0.05179	0.00608
Private DU	*0.00943	*0.03048	*0.02150	*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.

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.

Cluster ID	Feeder Technical Loss Cap	Non-Technical Loss Cap	Total DSL Cap
Cluster 1 (EC)	7.50%	4.50%	12.00% + DSLSS+ST
Cluster 2 (EC)	5.75%	4.50%	10.25% + DSLSS+ST
Cluster 3 (EC)	3.75%	4.50%	8.25% + DSLSS+ST
Cluster 4 (Private DU)	3.50%	1.25%	4.75 % + DSLSS+ST

III. Non-Technical Loss

Distribution Utilities have been required to submit summary of Non-Technical Loss in an annual basis. Aside from this, no other set of data were collected from Distribution Utilities that will allow analysis of Non-Technical 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.