Adopting the Rules for Approval of Regulated Entities' Capital Expenditure Projects

December 15, 2008

ERC RESOLUTION NO. 18-08

RESOLUTION ADOPTING THE RULES FOR APPROVAL OF REGULATED ENTITIES' CAPITAL EXPENDITURE PROJECTS

WHEREAS, Section 43 (f) of Republic Act No. 9136, otherwise known as the Electric Power Industry Reform Act of 2001 (EPIRA) provides that any significant operating costs or projects investments of the National Transmission Corporation (TRANSCO) and Distribution Utilities (DUs) which shall become part of the rate base shall be subject to verification by the Commission to ensure that the contracting and procurement of the equipment, assets and services have been subjected to transparent and accepted industry procurement and purchasing practices to protect the public interest;

WHEREAS, on March 8, 2006, the Commission adopted Resolution No. 13, Series of 2006 entitled "A Resolution Adopting the Guidelines to Govern the Submission, Evaluation and Approval of Electric Distribution Capital Projects", which provided the DUs with a uniform system of filing applications for approval of their respective proposed capital projects. aEAIDH

WHEREAS, in two (2) years of its implementation, several suggestions/comments were brought to the attention of the Commission to further improve said Guidelines;

WHEREAS, on May 29, 2003, the Commission adopted Resolution No. 04, Series of 2003 entitled "Adopting an Alternative Rate Setting Methodology for the National Transmission Corporation (TRANSCO) and Any Future Concessionaire Thereof" and the annex attached thereto entitled "Guidelines on the Methodology for Setting of Transmission Wheeling Rates" (TWRG); aEHTSc

WHEREAS, on April 11, 2006, the Commission adopted Resolution No. 16, Series of 2006 entitled "Adopting a Policy that Entry to the Performance Based Regulation (PBR) by Private Utilities Under the Distribution Wheeling Rates Guidelines (DWRG) be Made Mandatory";

WHEREAS, on July 26, 2006 and December 13, 2006, the Commission adopted Resolution No. 39, Series of 2006 entitled "Adopting the Rules for Setting the Distribution Wheeling Rates (RDWR) for Privately Owned Distribution Utilities Entering Performance Based Regulation (First Entry Point)" and Resolution No. 54, Series of 2006 entitled "Adopting the Rules for Setting the Distribution Wheeling Rates (RDWR) for Privately Owned Distribution Utilities Entering Performance Based Regulation (Second and Later Entry Points)", respectively;

WHEREAS, the Commission is in the process of formulating a new rate-setting methodology for Electric Cooperatives (ECs) which is envisaged to be implemented by 2009;

WHEREAS, the Commission deems it necessary to adopt a new set of rules that would address the suggested improvements and to make it consistent with the provisions of the TWRG, RDWR and the benchmarking methodology; DCTSEA

WHEREAS, on May 14, 2008, the Commission approved the first (1st) draft of the proposed Resolution Adopting the Rules for Approval of Regulated Entities' Capital Expenditure Projects and was posted in its official website at www.erc.gov.ph;

WHEREAS, on May 16, 2008, the Commission issued a Notice informing the public where they can secure a copy or access said proposed Rules and set the same for public consultation on June 16, 2008 at the ERC Visayas Field Office in Cebu City for all Visayas and Mindanao stakeholders and June 17, 2008 at the ERC Main Office in Pasig City for all Luzon stakeholders;

WHEREAS, in the same Notice, interested parties were directed to file their written comments/inputs on the said proposed Rules not later than June 12, 2008;

WHEREAS, on various dates, several regulated entities submitted their respective written comments/inputs on the said proposed Rules; THIcCA

WHEREAS, during the said public consultations, various stakeholders (privately owned DUs, commercial, industrial and residential consumers) were present and given opportunity to manifest their respective positions orally or in writing on the matters or issues presented in the proposed Rules;

WHEREAS, on November 10, 2008, the Commission approved the second (2nd) draft of the proposed Resolution Adopting the Rules for Approval of Regulated Entities' Capital Expenditure Projects and was posted in its official website;

WHEREAS, on November 11, 2008, the Commission issued a Notice directing all interested parties to file their written comments/inputs on the said 2nd revision of the proposed Rules not later than November 27, 2008;

WHEREAS, on various dates, the following entities filed their respective comments: Association of Mindanao Rural Electric Cooperatives, Incorporated (AMRECO), Northeast Luzon Electric Cooperative Association (NELECA), Philippine Chamber of Commerce and Industry (PCCI) and Cagayan Electric Light and Power Company, Incorporated (CEPALCO);

WHEREAS, the public consultations were held in preparation for issuance of the Rules for Approval of Regulated Entities' Capital Expenditure Projects; aEHIDT

NOW, THEREFORE, be it RESOLVED, as the Commission hereby RESOLVES to APPROVE and ADOPT the Rules for Approval of Regulated Entities' Capital Expenditure Projects, hereto attached and made an integral part of this Resolution as Annex "A".

This Resolution shall take effect fifteen (15) days upon its publication in a newspaper of nationwide circulation.

Let copies of this Resolution be furnished the University of the Philippines Law Center-Office of the National Administrative Register (UPLC-ONAR), all DUs and TRANSCO.

Pasig City, December 15, 2008.

(SGD.) ZENAIDA G. CRUZ-DUCUTChairperson

(SGD.) RAUF A. TANCommissioner

(SGD.) ALEJANDRO Z. BARINCommissioner

(SGD.) MARIA TERESA A.R. CASTAÑEDACommissioner

(SGD.) JOSE C. REYESCommissioner

ATTACHMENT

Distribution Utilities:

1. ANGELES ELECTRIC CORPORATION

2. FIRST BAY POWER CORPORATION

3. CABANATUAN ELECTRIC CORPORATION

4. PUBLIC UTILITIES DEPARTMENT (PUD-Olongapo)

5. DAGUPAN ELECTRIC CORPORATION

6. IBAAN ELECTRIC AND ENGINEERING CORPORATION

7. LA UNION ELECTRIC COMPANY, INC. HCacDE

8. SAN FERNANDO ELECTRIC LIGHT AND POWER COMPANY, INC.

9. TARLAC ELECTRIC INC.

10. MACTAN ELECTRIC COMPANY, INC.

11. PANAY ELECTRIC COMPANY, INC.

12. BOHOL LIGHT COMPANY, INC.

13. CAGAYAN ELECTRIC POWER AND LIGHT COMPANY, INC.

14. ILIGAN LIGHT AND POWER, INC.

15. MARIPIPI MULTI-PURPOSE COOPERATIVE (MMPC)

16. VISAYAN ELECTRIC COMPANY (VECO)

17. DAVAO LIGHT AND POWER COMPANY

18. COTABATO LIGHT AND POWER COMPANY

19. ILOCOS NORTE ELECTRIC COOPERATIVE, INC.

20. ILOCOS SUR ELECTRIC COOPERATIVE, INC.

21. LA UNION ELECTRIC COOPERATIVE, INC.

22. PANGASINAN I ELECTRIC COOPERATIVE, INC. cASIED

23. CENTRAL PANGASINAN ELECTRIC COOPERATIVE, INC.

24. PANGASINAN III ELECTRIC COOPERATIVE, INC.

25. BATANES ELECTRIC COOPERATIVE, INC.

26. CAGAYAN I ELECTRIC COOPERATIVE, INC.

27. CAGAYAN II ELECTRIC COOPERATIVE, INC.

28. ISABELA I ELECTRIC COOPERATIVE, INC.

29. ISABELA II ELECTRIC COOPERATIVE, INC.

30. NUEVA VIZCAYA ELECTRIC COOPERATIVE, INC.

31. QUIRINO ELECTRIC COOPERATIVE, INC.

32. ABRA ELECTRIC COOPERATIVE, INC.

33. BENGUET ELECTRIC COOPERATIVE, INC.

34. IFUGAO ELECTRIC COOPERATIVE, INC.

35. KALINGA APAYAO ELECTRIC COOPERATIVE, INC.

36. MOUNTAIN PROVINCE ELECTRIC COOPERATIVE, INC.

37. PENINSULA ELECTRIC COOPERATIVE, INC.

38. NUEVA ECIJA I ELECTRIC COOPERATIVE, INC.

39. NUEVA ECIJA II ELECTRIC COOPERATIVE, INC.

40. NUEVA ECIJA II ELECTRIC COOPERATIVE, INC. — AREA II cHaCAS

41. PAMPANGA I ELECTRIC COOPERATIVE, INC.

42. PAMPANGA II ELECTRIC COOPERATIVE, INC.

43. PAMPANGA III ELECTRIC COOPERATIVE, INC.

44. PAMPANGA RURAL ELECTRIC SERVICE COOPERATIVE, INC.

45. SAN JOSE CITY ELECTRIC COOPERATIVE, INC.

46. TARLAC I ELECTRIC COOPERATIVE, INC.

47. TARLAC II ELECTRIC COOPERATIVE, INC.

48. ZAMBALES I ELECTRIC COOPERATIVE, INC.

49. ZAMBALES II ELECTRIC COOPERATIVE, INC.

50. AURORA ELECTRIC COOPERATIVE, INC.

51. BATANGAS I ELECTRIC COOPERATIVE, INC.

52. BATANGAS II ELECTRIC COOPERATIVE, INC.

53. BUSUANGA ISLAND ELECTRIC COOPERATIVE, INC.

54. FIRST LAGUNA ELECTRIC COOPERATIVE, INC.

55. LUBANG ELECTRIC COOPERATIVE, INC.

56. MARINDUQUE ELECTRIC COOPERATIVE, INC.

57. OCCIDENTAL MINDORO ELECTRIC COOPERATIVE, INC.

58. ORIENTAL MINDORO ELECTRIC COOPERATIVE, INC. acIASE

59. PALAWAN ELECTRIC COOPERATIVE, INC.

60. QUEZON I ELECTRIC COOPERATIVE, INC.

61. QUEZON II ELECTRIC COOPERATIVE, INC.

62. ROMBLON ELECTRIC COOPERATIVE, INC.

63. TABLAS ISLAND ELECTRIC COOPERATIVE, INC.

64. ALBAY ELECTRIC COOPERATIVE, INC.

65. CAMARINES NORTE ELECTRIC COOPERATIVE, INC.

66. CAMARINES SUR I ELECTRIC COOPERATIVE, INC.

67. CAMARINES SUR II ELECTRIC COOPERATIVE, INC.

68. CAMARINES SUR III ELECTRIC COOPERATIVE, INC.

69. CAMARINES SUR IV ELECTRIC COOPERATIVE, INC.

70. FIRST CATANDUANES ELECTRIC COOPERATIVE, INC.

71. MASBATE ELECTRIC COOPERATIVE, INC.

72. SORSOGON I ELECTRIC COOPERATIVE, INC.

73. SORSOGON II ELECTRIC COOPERATIVE, INC.

74. TICAO ISLAND ELECTRIC COOPERATIVE, INC.

75. AKLAN ELECTRIC COOPERATIVE, INC.

76. ANTIQUE ELECTRIC COOPERATIVE, INC. aAEHCI

77. CAPIZ ELECTRIC COOPERATIVE, INC.

78. GUIMARAS ELECTRIC COOPERATIVE, INC.

79. ILOILO I ELECTRIC COOPERATIVE, INC.

80. ILOILO II ELECTRIC COOPERATIVE, INC.

81. ILOILO III ELECTRIC COOPERATIVE, INC.

82. CENTRAL NEGROS ELECTRIC COOPERATIVE, INC.

83. NEGROS OCCIDENTAL ELECTRIC COOPERATIVE, INC.

84. VMC RURAL ELECTRIC SERVICE COOPERATIVE, INC.

85. BANTAYAN ISLAND ELECTRIC COOPERATIVE, INC.

86. BOHOL I ELECTRIC COOPERATIVE, INC.

87. BOHOL II ELECTRIC COOPERATIVE, INC.

88. CAMOTES ISLAND ELECTRIC COOPERATIVE, INC.

89. CEBU I ELECTRIC COOPERATIVE, INC.

90. CEBU II ELECTRIC COOPERATIVE, INC.

91. CEBU III ELECTRIC COOPERATIVE, INC.

92. NEGROS ORIENTAL I ELECTRIC COOPERATIVE, INC.

93. NEGROS ORIENTAL II ELECTRIC COOPERATIVE, INC.

94. PROVINCE OF SIQUIJOR ELECTRIC COOPERATIVE, INC. SDTIHA

95. BILIRAN ISLAND ELECTRIC COOPERATIVE, INC.

96. EASTERN SAMAR ELECTRIC COOPERATIVE, INC.

97. NORTHERN SAMAR ELECTRIC COOPERATIVE, INC.

98. SAMAR I ELECTRIC COOPERATIVE, INC.

99. SAMAR II ELECTRIC COOPERATIVE, INC.

100. LEYTE I ELECTRIC COOPERATIVE, INC.

101. LEYTE II ELECTRIC COOPERATIVE, INC.

102. LEYTE III ELECTRIC COOPERATIVE, INC.

103. LEYTE IV ELECTRIC COOPERATIVE, INC.

104. LEYTE V ELECTRIC COOPERATIVE, INC.

105. SOUTHERN LEYTE ELECTRIC COOPERATIVE, INC.

106. BASILAN ELECTRIC COOPERATIVE, INC.

107. SULU ELECTRIC COOPERATIVE, INC.

108. CAGAYAN DE SULU ELECTRIC COOPERATIVE, INC.

109. SIASI ELECTRIC COOPERATIVE, INC.

110. TAWI-TAWI ELECTRIC COOPERATIVE, INC.

111. ZAMBOANGA CITY ELECTRIC COOPERATIVE, INC.

112. ZAMBOANGA DEL NORTE ELECTRIC COOPERATIVE, INC. ESTDIA

113. ZAMBOANGA DEL SUR I ELECTRIC COOPERATIVE, INC.

114. ZAMBOANGA DEL SUR II ELECTRIC COOPERATIVE, INC.

115. AGUSAN DEL NORTE ELECTRIC COOPERATIVE, INC.

116. AGUSAN DEL SUR ELECTRIC COOPERATIVE, INC.

117. FIRST BUKIDNON ELECTRIC COOPERATIVE, INC.

118. BUKIDNON II ELECTRIC COOPERATIVE, INC.

119. CAMIGUIN ELECTRIC COOPERATIVE, INC.

120. DINAGAT ISLAND ELECTRIC COOPERATIVE, INC.

121. MISAMIS OCCIDENTAL I ELECTRIC COOPERATIVE, INC.

122. MISAMIS OCCIDENTAL II ELECTRIC COOPERATIVE, INC.

123. MISAMIS ORIENTAL I ELECTRIC COOPERATIVE, INC.

124. MISAMIS ORIENTAL II ELECTRIC COOPERATIVE, INC.

125. SIARGAO ELECTRIC COOPERATIVE, INC.

126. SURIGAO DEL NORTE ELECTRIC COOPERATIVE, INC.

127. DAVAO DEL NORTE ELECTRIC COOPERATIVE, INC.

128. DAVAO ORIENTAL ELECTRIC COOPERATIVE, INC.

129. DAVAO DEL SUR ELECTRIC COOPERATIVE, INC. DHIaTS

130. SOUTHERN COTABATO I ELECTRIC COOPERATIVE, INC.

131. SOUTHERN COTABATO II ELECTRIC COOPERATIVE, INC.

132. SURIGAO DEL SUR I ELECTRIC COOPERATIVE, INC.

133. SURIGAO DEL SUR II ELECTRIC COOPERATIVE, INC.

134. LANAO DEL NORTE ELECTRIC COOPERATIVE, INC.

135. LANAO DEL SUR ELECTRIC COOPERATIVE, INC.

136. MAGUINDANAO ELECTRIC COOPERATIVE, INC.

137. NORTH COTABATO ELECTRIC COOPERATIVE, INC.

138. SULTAN KUDARAT ELECTRIC COOPERATIVE, INC.

139. NATIONAL TRANSMISSION CORPORATION

ANNEX A

RULES FOR THE APPROVAL OF REGULATED ENTITIES' CAPITAL EXPENDITURE PROJECTS

Pursuant to Section 43 (f) of Republic Act No. 9136, otherwise known as the Electric Power Industry Reform Act of 2001 (EPIRA), Rule 7 and Rule 15 Section 5 (a) of its Implementing Rules and Regulations (IRR), the Distribution Services and Open Access Rules (DSOAR) and Section 20 (b) of Commonwealth Act No. 146, as amended, the Energy Regulatory Commission (ERC) hereby promulgates the following Rules for Approval of Regulated Entities' Capital Expenditure Projects. IHcTDA

ARTICLE I

General Provisions

1.1 Objectives

1.1.1 To provide the Regulated Entities with a uniform system for filing applications for the approval of capital expenditure projects;

1.1.2 To ensure that projects are timely, appropriate, necessary and cost-efficient;

1.1.3 To ensure that proposed capital projects are consistent with the Distribution Development Plan (DDP), the Philippine Grid Code (PGC), the Philippine Distribution Code (PDC), and other relevant government issuances; and

1.1.4 To ensure that the procurement of equipment, materials and services are transparent, competitive and compliant with the applicable laws and regulations.

1.2 Scope of Application

These Rules shall apply to all Regulated Entities, including but not limited to the following:

1.2.1 Electric Cooperatives;

1.2.2 Local Government Unit Owned-and-Operated Distribution Systems;

1.2.3 Qualified Third Parties (QTPs) operating in waived areas of a franchised Distribution Utility; and cDECIA

1.2.4 Consortium of Distribution Utilities.

1.3 Definition of Terms

Capital Projects	Those projects that are needed to serve
	forecasted future loads and to maintain
	good electric service to existing and
	future customers satisfying the utility's
	technical criteria for capacity,
	reliability, quality and safety.
Distribution Connection	Those assets that are put primarily to
Assets	connect a Generator or an End-User to
	the Distribution System for purposes of
	Distribution Connection Services for
	the conveyance of electricity.
	Those are facilities which may be
	bypassed or removed from the network
	without affecting any customer except
	those that are directly connected to it.
	This is also known as the Standard
	Connection Facility as provided in the
	DSOAR.
Department of Energy (DOE)	The government agency created
	pursuant to Republic Act No. 7638, the
	Department of Energy Act of 1992,
	whose expanded functions are
	provided in the EPIRA.
Distribution Development	The five-year development plan
Plan (DDP)	submitted by the Distribution Utilities
	to the DOE not later than the fifteenth
	(15th) of March of every year, pursuant
	to Section 23 of the EPIRA and Rule 7,
	Section 4 (p) of its IRR. In the case of
	Electric Cooperatives, such plans
	submitted through the National
	Electrification Administration for
	review and consolidation.
Electric Cooperative (EC)	A Distribution Utility organized
	pursuant to Presidential Decree No.
	269, as amended or as otherwise
	provided in the EPIRA.
Equipment	All apparatus, machines, conductors,
	etc. used as part of, or in connection
	with, an electrical installation.
Force Majeure	A typhoon, storm, tropical depression,
	flood, drought, volcanic eruption,
	earthquake, tidal wave or landslide.
Fortuitous Event	An act of public enemy, war (declared
	or undeclared), sabotage, blockade,
	revolution, riot, insurrection, civil
	commotion or any violent or
	threatening actions.
High Voltage (HV) Lines	A voltage level exceeding 34.5kV up
	to 230 kV. Generally, lines on this
	level are considered either
	subtransmission line needed for
	connection to transmission network or
	a primary distribution circuits that
	satisfy the (n-1) reliability criterion.
Low Voltage (LV) Lines	A voltage level not exceeding 1000
	volts. Generally, lines on this level are
	radial in configuration and the (n-1)
	reliability criteria are not considered.
Medium Voltage (MV) Lines	A voltage level exceeding one (1) kV
	up to 34.5 kV. Generally, lines on this
	level are radial in configuration and the
	(n-1) reliability criteria are not
	considered.
Network Assets	Those assets forming part of the
	Regulatory Asset Base that are
	required to provide Regulated
	Services, i.e., distribution Connection
	Assets.
Non-network Assets	Those assets forming part of the
	Regulatory Asset Base that are
	required to provide Regulated
	Services, but are not Network Assets or
	Connection Assets.
Philippine Distribution Code	The set of basic rules, requirements,
(PDC)	procedures, and standards governing
	Distribution Utilities and Users in the
	operation, maintenance, and
	development of their Distribution
	Systems. It also defines and establishes
	the relationship of the Distribution
	Systems with the facilities or
	installations of the parties connected
	thereto.
Philippine Grid Code (PGC)	The set of basic rules, requirements,
	procedures, and standards to ensure the
	safe, reliable, secured and efficient
	operation, maintenance, and
	development of the high-voltage
	backbone Transmission System and its
	related facilities.
Power Supplier	An organization from which the
	Regulated Entity purchases wholesale
	power and energy. The role of the
	power supplier may be filled by a
	private power company, a
	governmental agency, or an
	independent power producer. In many
	cases, the Regulated Entity purchases
	energy from more than one power
	supplier. In cases where all purchases
	are coordinated through one
	organization, that organization is the
	power supplier even if that
	organization has no generating
	capacity of its own.
Regulated Distribution	In respect of a Regulated Distribution
Services	System:
	a)	the conveyance of electricity
		through the Regulated System and
		the control and monitoring of
		electricity as it is conveyed through
		the Regulated System (including
		any service that supports such
		conveyance, control or monitoring
		or the safe operation of the
		Regulated Distribution System);
	b)	the planning, maintenance,
		augmentation and operation of the
		Regulated System;
	c)	the provision, installation,
		commissioning, testing, repair,
		maintenance and reading both of
		meters that are used to measure the
		delivery of electricity to persons
		whose User Systems or Equipment
		is directly connected to the
		Regulated System and of other
		meters that are used (for the
		purposes of the Wholesale
		Electricity Spot Market) to measure
		the flow of electricity into or
		through the Regulated System;
	d)	Distribution Connection Services in
		respect of the Regulated System
		except to the extent that such
		Connection Services have been
		determined by the ERC to be
		excluded;
	e)	the provision of Ancillary Services
		that are provided using assets which
		form part of the Regulated System
		(excluding any such Ancillary
		Services to the extent they are
		provided to the System Operator
		under contract or through a spot
		market established under the
		WESM Rules); and
	f)	billing, collection and customer
		services that are directly related to
		the delivery of electricity through
		the Regulated System to
		Connection Points in respect of the
		Regulated System and billing,
		collection and customer services for
		persons purchasing or receiving (or
		seeking to purchase or receive) any
		Connection Service in respect of
		the Regulated System.
		These services, however, do not include
		such services as are determined by the
		ERC to be contestable.
Regulated Distribution	A Distribution System which is located
System	in a Qualified Franchise Area and
	operated under an exclusive franchise
	and operated only by the Regulated
	Entity that operates that Distribution
	System.
Regulated Entity	Any entity or entities who provide any
	Regulated Distribution Service in
	respect of a Regulated System, but
	excluding such persons as the ERC
	determines from time to time. The
	Regulated Entities include the
	Privately-owned DUs, Electric
	Cooperatives, Local Government Unit
	Owned-and-Operated Distribution
	Utilities, Qualified Third Parties
	(QTPs) operating in waived areas of a
	franchised Distribution Utility; and
	Other duly regulated entities including
	Consortium of Distribution Utilities.
Regulatory Asset Base	Those assets employed by a Regulated
	Entity to provide efficient Regulated
	Distribution Services. It covers the
	Regulated Distribution System Assets
	as well as the Non-network Assets
	required to support the delivery of
	Regulated Services.
System Planning	The careful analysis and evaluation of
	an electric power system, the
	consideration of alternative methods of
	meeting the electric power needs of the
	consumers, and the selection of the
	most promising of the viable
	alternatives for providing reliable,
	environmentally acceptable service at
	reasonable cost.

ARTICLE II

Classification of Capital Expenditure Projects

2.1 Capital Asset Categories

Regulated Entities' capital assets are divided into two (2) categories, namely: (1) regulated distribution assets; and (2) distribution connections assets. The regulated distribution assets are further divided into two subcategories, namely (a) distribution plant assets or network assets; and (b) general plant assets or non-network assets. CaAcSE

2.1.1  The following constitute the distribution plant (network) assets:

• Land and land rights — this shall be dedicated to the distribution and subtransmission purposes and shall include the cost of land and land rights used in connection with distribution operations. This shall not include the costs of permits to erect poles, towers, etc., or to trim trees.

• Structures and improvements — this shall be dedicated to the distribution and subtransmission purposes and shall include the cost of structures and improvements used in connection with distribution operations.

• Station equipment — switchyards, power transformers, switchgear, protective equipment, metering, control, communications equipment, Supervisory Control and Data Acquisition equipment (SCADA) — this shall include the installation cost of substation equipment, including transformer banks, protection installation, switchgear, communication systems, etc., which are used for the purpose of converting voltage levels or controlling and directing the flow of electricity through the distribution network.

 The cost of rectifiers, series transformers, and other special station equipment devoted exclusively to street lighting service shall be included in Street Lights and Signal Systems.

• Poles, towers and fixtures/hardwares — this shall include the installation cost of poles, towers, and auxiliary fixtures used for supporting overhead distribution conductors and service wires.

• Overhead conductors and devices — this shall include the installation cost of overhead conductors and other overhead devices used for distribution purposes. The cost of conductors used solely for street lighting or signal systems shall be included in Street Lights and Signal Systems. cDAISC

• Underground conduits/raceways — this shall include the installation cost of underground conduit and tunnels used for housing distribution cables or wires. The cost of underground conduit used solely for street lighting or signal systems shall be included in Street Lights and Signal Systems.

• Underground conductors and devices — this shall include the installation cost of underground conductors and associated devices used for distribution purposes. The cost of underground conductors and devices used solely for street lighting or signal systems shall be included in Street Lights and Signal Systems.

• Distribution line transformers and circuit reclosers — this shall include the installation cost of overhead and underground distribution line transformers and pole-type and underground voltage regulators owned by the utility, for use in transforming electricity to voltage at which it is to be used by the customer. The cost of line transformers used solely for street lighting or signal systems shall be included in Street Lights and Signal Systems. SaAcHE

• Power conditioning equipment — this refers to equipment such as capacitor banks for power factor correction, synchronous condensers, static VAR compensators, line filters, voltage regulators, generators used to provide spinning reserve or voltage stability, etc.

• Meters, metering instruments & metering transformers

 As far as it pertains to customer assets, this shall include the installation cost of meters or devices and accessories thereto, for use in measuring the electricity delivered to its users, whether actually in service or held in reserve.

 As far as it pertains to distribution assets, this shall include meter installations for monitoring energy flows at various points in the system, as well as meters installed to monitor and manage system losses.

• Information technology equipment — any other information technology equipment that are dedicated to distribution purposes and are used to manage the distribution networks that are not already included under substation or similar categories. CHcETA

• Regulated entity property on consumers' premises

 Installations on Customers' Premises

 This shall include the installation cost of equipment on the customer's side of a meter when the utility incurs such cost and when the utility retains title to and assumes full responsibility for maintenance and replacement of such property.

 Leased Property on Customers' Premises

 This shall include the cost of electric motors, transformers, and other equipment on customers' premises (including municipal corporations), leased or loaned to customers, but not including property held for sale.

• Street Lights and Signal Systems — this shall include the installation cost of equipment used wholly for Public Street and highway lighting or traffic, fire alarm, police, and other signal systems.

• Submarine cable system — this shall include the installation cost of submarine cables and associated devices used for distribution purposes. TCaAHI

2.1.2  The following constitute the general plant assets (non-network) are:

• Land and land rights (non-network related) — this shall include the cost of land and land rights used for utility purposes.

• Structures and improvements (non-network related) — this shall include the cost in place of structures and improvements used for utility purposes.

• Office furniture and equipment — this shall include the cost of office furniture and equipment owned by the utility and devoted to utility service, and not permanently attached to buildings, except the cost of such furniture and equipment assign to other plant on a functional basis.

• Transportation equipment — this shall include the cost of utility and transportation vehicles used for utility purposes.

• Stores equipment — this shall include the cost of equipment used for the receiving, shipping, handling, and storage of materials and supplies.

• Tools, shop, safety gadgets and garage equipment — this shall include the cost of tools, implements, and equipment used in construction, repair work, general shops and garages and not specifically provided for in other account. cHITCS

• Laboratory equipment — this shall include the cost of laboratory equipment used for general laboratory purposes and not specifically provided for in other departments or functional plant accounts.

• Information systems equipment — this shall include all information system equipment used to provide support services to the distribution function, including desktop computers, software, back-up storage devices, computer network assets, UPS or similar systems, etc.

• Power-operated equipment — this shall include the cost of power operated equipment used in construction or repair work exclusive of other equipment. Likewise includes the tools and accessories acquired for use with such equipment and the vehicle on which such equipment is mounted.

• Communication plant and equipment — this shall include the installation cost of telephone, telegraph, and wireless equipment for general use in connection with utility operations. It shall exclude any items included under the information system category. AaDSTH

• Miscellaneous equipment — this shall include the cost of equipment, apparatus, etc., used in the utility operations, which is not included in any other account enumerated in this Rule.

• Materials and supplies, including spares:

 Materials and Supplies — Electric

 This represents the cost of materials purchased primarily for use in the conduct of utility business for construction, operation and maintenance purposes and materials recovered in connection with construction, maintenance or retirement of property. This includes (1) cost of electric materials and supplies purchased, (2) freight, insurance, unloading, handling and other transportation charges, if can be directly assigned to particular purchases, and (3) cost of special tests of materials prior to acceptance.

 Materials and Supplies — Others

 This represents cost of materials and supplies held primarily for use in the repairs and maintenance of general plant items such as vehicles, office equipment and like items.

 Office Supplies — this represents the cost of postage, stationery and all other office supplies on hand. TDCaSE

 Stores Expense Undistributed

 This shall include the cost of freight and delivery charges not directly identifiable to each type of materials and supplies purchased. This account shall be cleared by adding to the cost of materials and supplies issued a prorated amount of freight and delivery charges to distribute the expenses equitable over stores issues. This includes (1) freight, delivery and handling charges of materials and supplies purchased when not assignable to specific items, (2) adjustments of inventories of materials but not including large differences which can readily be assigned to important classes of materials and equitably distributed among the accounts to which such class of materials were charged since the previous inventory, and (3) excise and other similar taxes (paid on materials and supplies purchased) not assignable to specific materials; and

• Any other asset specified by the ERC.

2.1.3  The distribution connection assets are:

Those assets that are put primarily to connect a Generator or an End-User to the Distribution System for purposes of Distribution Connection Services for the conveyance of electricity. IHDCcT

Those are facilities which may be bypassed or removed from the network without affecting any customer except those that are directly connected to it.

This is also known as the Standard Connection Facility as provided in the DSOAR.

2.2 Planning Criteria of Capital Assets

2.2.1  Demand and Growth Projection

The maximum capacity of any part of the network shall be determined by the allowed future load growth, which is the maximum forecast load on the relevant part of the network under contingency operating conditions over the allowed planning period.

In order to ensure compliance with this clause, when preparing project valuations Regulated Entities shall disclose both existing loads and the load forecast used as a basis for technical analysis. As a minimum, existing and forecast loads shall be provided for each grid connection point, each main substation and each high voltage distribution feeder. Clear justification and a detailed derivation of the load growth forecasts are required. Both the existing maximum demand and the highest forecast maximum demand during the planning period shall be provided.

Allowances should be made, where possible, for different growth rates in different parts of the network. Existing loads may be estimated where metering is not available.

The load forecast shall include only future electricity loads that can reasonably be expected to be supplied from the distribution network. A load outside the existing geographic boundaries of a Regulated Entity's area of supply shall not be included in the forecast unless a written customer contract to supply the load exists at the time of the project valuation. acCDSH

2.2.2  Planning Horizon

Proposed capital projects of Regulated Entities must be economically efficient and therefore must be planned and studied thoroughly. While it is prudent to install assets with some surplus capacity to cater to future growth in demand, it is not economically efficient to install assets where the capacity is so large that it would not be fully-utilized at the end of the assets' economic life.

The planning periods over which future load growth can be allowed for shall not exceed the following:

a) Fifteen (15) years for high voltage (HV) lines or subtransmission lines, substations (excluding transformers), primary distribution circuits and points of connection to a transmission network;

b) Ten (10) years for substation transformers; and

c) Five (5) years for medium voltage (MV) and low voltage (LV) distribution, and other network assets. cEaACD

Alternative planning periods may be adopted depending on the appropriate concentration of business districts, density of urbanized areas or geographic locations and conditions. Such planning periods must be properly justified.

The appropriate span of the planning period is a function of the following factors:

a) The anticipated load levels at the end of the planning period.

b) The forecasted growth rate of the system or major portions of the system;

c) The age of the electrical supply facilities, both at the beginning and the end of the period. Particular attention must be given to the percentage of the facilities which are or will be beyond their useful life; and, ICacDE

d) The validity of the future economic factors, such as inflation rate, especially toward the end of the planning period, which are being used for the engineering economic analysis of the alternate plans in the study.

2.2.3  Design Consideration

The network shall be designed to supply the existing load, and the allowed future load growth, with a quality of supply compliant with existing rules and regulations. Further, the system shall also be designed to provide adequate, reliable, and quality service at a reasonable cost to all consumers. The following shall be considered in the design of the system.

a) Power Sources: The capacity and adequacy of all existing and prospective power sources shall be considered. If the source is unable to supply the necessary quantity of power for its area, if the interruption record is poor, or if voltage levels will be inadequate, then alternative sources of power shall be considered. Interruption data should be recorded and evaluated on a regular basis for all existing power sources and interruption rates for prospective sources shall be estimated based on records for facilities with similar characteristics. HADTEC

b) High Voltage (HV) Lines: It is extremely important that the planning of distribution system be coordinated with the power supplier regarding HV or subtransmission lines. Whether the HV or subtransmission lines are part of the distribution system or owned by the power supplier, planning shall be approached on a "one system" concept. This concept provides proper coordination of the distribution systems with the power supplier regardless of who owns the lines.

 Excessive costs for HV or subtransmission facilities cannot be justified by minor savings on one part of the system. The converse is also true that excessive distribution plant shall not be constructed simply to avoid HV construction. HV facilities which are well planned will provide high continuity of service, long life of physical equipment, and safe operation at relatively low overall cost. The following factors shall be determined for all HV lines.

• The proposed line length, line-end points and future extensions should be approximated. EcHaAC

 

• The voltage class of the HV lines should generally be determined by the voltage of the line to be tapped. Occasionally an exception is justified due to superior reliability for a small increase in cost or where total benefits outweigh the added cost of the alternative.

• HV conductors should be tentatively sized based on economic studies taking into consideration line losses, present and future power requirements, cost of upgrading the line when the conductor is no longer adequate, and the cost of carrying excess capacity until it is needed. Cost of stocking and hardware standardization shall also be considered where a new conductor size has been indicated by other factors.

• Environmentally sensitive areas along the corridor proposed for line routing shall be avoided if possible. Also right-of-way requirements shall be considered.

• At least a rough check for stability and load flow characteristics should be made and if it indicates the need for a detailed project review, more extensive studies (computer load flow, stability and transient network analyzer studies) should be performed. In some cases, load flow studies will influence the location and timing of major substation additions. These studies shall be coordinated with the power supplier. HDAaIS

• The economy of radial feed substations shall be weighed against the reliability of loop feed substations. The applicability of each design, as it pertains to the basic system design and established operating practices, shall be carefully considered. Any proposed changes shall be coordinated with the power supplier if applicable.

• Acceptable subtransmission system voltage levels and variations from no-load (or light-load) to peak load as provided in the PGC and PDC based on service voltage at a point of delivery, subtransmission line characteristics, load growth, type of load, distribution substation transformer characteristics, ability to regulate voltage on the distribution bus, and contractual provisions. HAIDcE

c) Substations: A major decision to be made in long term planning is the optimum number and size of substations needed to provide services to the system. If possible, the cost and reliability of additional substations should be weighed against the cost and reliability of other alternatives. Decisions as to the exact location of substations shall be reserved for consideration in planning the electric capital project in the short term with only relative locations considered in the long term planning.

 Transformer capacity will be based on the accepted planning horizon, load growth projections, voltage stability, fault levels, reliability criteria and cyclic ratings, each transformer shall be examined for suitable rating.

 As a guide, the projected maximum demand on each substation at the end of the chosen planning period should not be less than 70% of the total installed capacity of the substation.

d) Reliability: Generally, shorter lines from smaller substations will lead to higher reliability; however, line reclosers and sectionalizers will improve reliability to some extent on long radial lines. Multiple substation transformers (four single-phase or two three-phase units), loop feeds into substations, and the availability of a mobile transformer or mobile substation all improve reliability. The decision on the size and number of substations needed in long term planning shall be made based in part on system experience with the source of interruption hours and the cost of improving reliability in those areas. cIECTH

 It is not always possible to use the most economical system configuration (conductor size, line voltage and number of phases) and still meet system standards for voltage levels, service reliability and economy. Service reliability shall be improved to any portion of the line of supply to the consumer where it can be done at a reasonable expense.

e) Medium Voltage (MV) and Low Voltage (LV) Lines: Whether medium voltage and low voltage lines are constructed overhead or underground, effective planning is needed to avoid premature obsolescence of facilities. Regulated Entity shall have performed a study of economic standard conductor sizes that will give guidance in selection of conductor size, circuit voltage and number of phases for economic construction and operation of new and converted overhead and underground distribution lines.

• It is necessary to consider many factors in determining whether distribution line construction shall be overhead or underground. Overhead lines generally involve lower construction costs and ease of constructing additions and of maintenance. Underground lines generally have less environmental concerns, are less affected by storms, have lower line losses and less voltage drop for a given ampacity. However, underground lines are sometimes subject to certain technical problems, such as difficulty in adding voltage control or sectionalizing equipment, and high replacement costs.

• Distribution lines shall meet the voltage standards required in the PGC and PDC or any more stringent local regulations when required. HcaDTE

• In spite of the high cost of rebuilding lines, and careful planning, it will often be necessary to increase the capacity of existing sections of distribution line. Before deciding to rebuild a line, careful consideration shall be given to a number of factors including:

a) If the line is quite old and will need replacement by the end of the planning period, then rebuilding with increased capacity may be a better way of obtaining increased ability to serve load than building an additional line. In some cases, considerable research may be needed to determine the age of various lines. However, rough estimates of effective age considering the amount of maintenance which has been performed will be adequate for these purposes.

b) Since the rebuilding operation will probably require replacement of most if not all poles, a different route may now be more desirable than the original one. For example, a line originally constructed on a right-of-way remote from the highway might be moved adjacent to the highway providing more economical maintenance of both the line and the right-of-way, with perhaps a net increase in reliability. Environmental considerations or territorial limitations of course, may preclude any rebuilding of lines in a given area. The alternatives shall be considered carefully before a decision is made to re-route a distribution line. DISEaC

c) It may be practical to serve sections from an alternate circuit or substation for a time until an improvement is constructed.

d) If another system improvement, such as a new substation or an additional new feeder, is planned for the area in the not too distant future, then the earlier construction of the other planned improvements shall be considered. DCcHIS

• When new distribution lines are needed, the routes shall be chosen, where feasible, to be along improved roads to facilitate operation and maintenance and to provide maximum opportunity to serve existing and potential consumers.

• Where it might be advantageous to change the system standard distribution voltage class, consideration shall be given to all standard distribution voltage classes. Frequently only one alternative voltage will be feasible; however, occasionally a voltage class which was not considered at first will provide greater long-term benefits. After a voltage conversion has been made, a further conversion will not be feasible as many of the costs associated with another change would be incurred a second time with a smaller offsetting savings.

• Virtually all systems use voltage regulators to maintain adequate voltage levels at extremities of distribution lines until major improvements can be justified. Line drop compensation, which can improve operation and/or extend the range of voltage regulators, shall be taken into consideration.

• Consideration shall also be given to the installation and optimum location of shunt capacitors on distribution lines. Capacitors provide a relatively low cost means to boost voltage and improve and control power factor. These improvements usually result in some demand reductions, energy conservation and lower power costs. Some voltage regulations can be achieved with the judicious sizing and locating of (usually switched) capacitor banks. THcaDA

2.2.4  Continuing Planning Activities: Planning for the future is a continuing process. Data shall continually be collected to check the soundness of the existing plan and later to aid in preparing a new plan. The Regulated Entity shall establish methods for obtaining the required data from various operating records and files. Good system planning requires methods for keeping the plan up-to-date. It shall also provide for electric capital projects to implement the transition through timely installation of facilities.

2.3 Priorities of Capital Expenditures

Rank: The project ranking should be indicated, based on the assessment of the Regulated Entity. This ranking can be in one of two tiers, as described below. By definition, capital expenditure should only be proposed when it is of high importance to maintain effective delivery standards, so projects of lesser importance should not be considered.

Projects deemed essential — 1st priority

• to improve the quality, reliability, efficiency and safe operation of the distribution network; ESTcIA

• to attain the minimum capacity, reliability and quality levels to meet required service delivery standards; or

• to provide very significant economic or technical benefits if implemented.

Failing to execute these projects at the time indicated would have a substantial impact on the ability of the Regulated Entity to provide efficient service in the short-term future (less than or equal to eighteen months) or would lead to substantial potential economic or technical benefits not being realized.

Projects deemed important (but not critical) — 2nd priority

 

• to maintain the efficient, reliable and safe operation of the distribution network;

• to provide the delivery capacity and reliability levels to meet required service delivery standards; or

• to provide marginal economic or technical benefits.

Failing to execute these projects at the time indicated would not have a major direct impact in the short-term but would compromise the ability of the Regulated Entity in the medium term (greater than eighteen months but less than or equal to three years) to provide efficient services, or could lead to potential economic or technical benefits not being achieved. cSDIHT

2.4 Capital Expenditure Project Driver:

The project driver should indicate the main driver for the project. (Where a project has more than one driver, the dominant one should be indicated.) Five categories of project drivers are considered:

Load Growth	These are projects required to meet the
	growing energy demand by consumers.
Network non-growth	These are projects required to maintain or
	improve network service delivery standards
	where not directly dictated by demand
	growth.
Network Control/Safety	These are projects required to improve
Metering	network safety or the control or management
	capability of the network (including the
	ability to measure performance).
Non-network	These are projects for developing
	administrative and support facilities and
	capabilities, which are not directly
	network-related.
Statutory	These are projects imposed by other parties,
	by regulation or by law. It includes
	requirements by others to shift existing assets.

 

2.5 Capital Expenditure Project Type

The project type classification indicates the type of project, classified in one of four categories.

Renewal (replacement)	Renewing assets where existing assets have
	become non-functional or obsolete, or where
	the continued refurbishment or maintenance
	of assets would have a higher economic cost
	than renewing them.
Refurbishment	Projects to extend the useful lives of existing
	assets, normally to beyond their standard
	lives.
Growth	Installing new assets to meet growing
	demand or higher service level requirements.
Rural Electrification	These are projects involving installation of
	plant assets to provide electricity in far-flung
	areas (missionary electrification).

To avoid confusion over what constitutes load growth, renewal or refurbishment related projects, the following should be noted.

a) Projects undertaken to provide Regulated Distribution Services to new Customers or to increase the capacity of Regulated Distribution Systems in order to meet growing demands for Regulated Distribution Services from existing Customers, should be classified as load growth projects. SHADEC

b) Projects undertaken to expand assets because they can no longer meet growing demands should be classified as load growth projects.

c) Renewal projects are those that replace existing assets due to their deteriorating condition, when the anticipated economic cost of operating, refurbishing and maintaining these assets exceed that to renew them.

d) Renewal projects can also refer to those intended to replace assets due to technological obsolescence.

e) There is often a significant degree of overlap between maintenance and refurbishment projects. In general, maintenance works are defined as those works required ensuring that an asset performs its designated function for its full standard asset life. Refurbishment projects on the other hand, are those that are used to increase the serviceability of assets beyond their normal standard asset lives. Expenses incurred for maintenance activities should not be capitalized. THCSEA

f) Refurbishment projects often involve at least a degree of asset replacement, which may give rise to some ambiguity. Such projects should be classified in accordance with their underlying activities that constitute the largest part of the project value.

2.6 Capital Expenditure Project Need

The Regulated Entity shall provide a statement explaining the need for the project, which shall include but not limited to the following:

• Project purpose: A statement or description of what the project is intended to achieve.

• Impact if not implemented: The expected outcome if the project does not proceed or is delayed should be described (typically in terms of supply capacity, reliability, functionality, performance indicators, safety or similar factors). Specific provisions of system conditions or local requirements which determine the need for the proposed project; SCEDaT

• Reason for ranking the project commissioning date: A statement or description of justification for scheduling the project as proposed.

2.7 Detailed Technical Description and Cost Estimate

Detailed technical descriptions and project cost estimates, down to a major component level should be provided. This is to assess the reasonableness of the application.

The technical project description can be supported with single line diagrams, construction drawings, route drawings or similar information. Relevant load flow studies, reliability studies, contingency analyses, or similar studies, if appropriate; identifying the need for system improvement shall also be provided.

For the cost estimates, labor and material costs should be separately indicated. In addition to component breakdown, details are also to be provided of the forecast cash-flow required for the project.

2.8 Performance Measures With/Without Project

Measurable indices should be provided against which forecast outcomes with the project in place can be compared with those same outcomes if the project is not put in place. These indices can be qualitative or quantitative. AHCaES

Qualitative — performance measures would be used where the impact of completing the project cannot be readily measured against useful numerical indices. (An example would be the acquisition of new software to manage administrative functions, which may greatly improve administrative capability in various ways but where such improvement cannot easily be quantified, or where comparative historical performance data does not exist.)

Quantitative — performance measures would be applied where the anticipated impact of the project can be measured in numerical terms. This is useful if broken down into the impact per calendar year for short-term or longer-term future (as appropriate). (An example would be the anticipated SAIDI on the part of the network affected by the project, or the anticipated loading of equipment — with or without the project in place.)

2.9 Expenditure on the Acquisition of Subtransmission Assets

If applicable, any capital expenditure for the acquisition of TransCo's subtransmission assets included in the planned three (3)-year capital expenditure program should also be included in the capitalized forecast. The capitalized cost of the assets should be the price as approved by the ERC.

2.10 Capitalization of Operating or Maintenance Expenses

The International Accounting Standards (IAS) adopted in the Philippines will apply with regard to the capitalization of operating and maintenance expenses by Regulated Entities. In general, only those operating expenses incurred directly in the course of establishing capital assets can be capitalized to become part of the value of the associated assets and therefore to be included in the capital expenditure forecasts. TSIaAc

Cost components that can be capitalized are:

• purchase price, including import duties and non-refundable purchase taxes, and any directly attributable costs of bringing the asset to working condition for its intended use, e.g., cost of site preparation, initial delivery and handling costs, installation costs, professional fees such as for architects, engineers and project managers, and estimated cost of dismantling and removing the asset and restoring the site, and the estimated costs of dismantling and removing the asset as a provision under IAS 37, Provisions, Contingent Liabilities and Contingent Assets;

• borrowing costs allowed under IAS 23, to the extent that these are not already recovered through the CWIP factor;

• administration and other general overhead costs and start-up and similar pre-production costs which are directly attributed to the acquisition of the property, plant and equipment and/or bringing the asset to its working condition; and DaTEIc

• major spare parts and stand-by equipment qualifying as property, plant and equipment. 1

For subsequent expenditures on assets, capitalization shall be done only when it is probable that future economic benefits, in excess of the originally assessed standard of performance of the existing asset, will flow to the enterprise. As such, the expenditure improves the condition of the asset beyond its originally assessed standard of performance, as follows:

• modification of an asset to extend its useful life, or increase its capacity;

• upgrade of assets to achieve a substantial improvement in the quality of output; and

• adoption of new production processes enabling a substantial reduction in previously assessed operating costs.

The following items are to be excluded from capitalized costs:

• any trade discounts and rebates given in relation to the asset;

• initial operating losses incurred prior to an asset achieving planned performance; cAaETS

• applicable government grants in accordance with IAS 20 (Accounting for Government Grants and Disclosure of Government Assistance); and

• expenditure on repairs or maintenance of property, plant and equipment made to restore or maintain the future economic benefits that an enterprise can expect from the originally assessed standard of performance of the asset. For example, the cost of servicing or overhauling plant and equipment is usually a maintenance expense since it restores, rather than increases, the originally assessed standard of performance.

Regulated Entities have to describe their general approach to capitalization of expenses. Any administrative, management, governance or other overhead costs to be capitalized must be separately identified to the ERC in the capital expenditure forecasts, together with the justification for this decision and the manner in which the costs involved are calculated. The ERC may decide to accept the reasonableness costs as part of the capital expenditure forecasts, or may decide to reclassify them as operating and maintenance costs (if deemed efficient and reasonable). ESTCHa

 

ARTICLE III

Filing of the Application

3.1 Time of Filing of Capital Expenditure Program

A Regulated Entity shall submit its proposed three (3)-year capital expenditure program in accordance with the prescribed groupings and schedule. The grouping is appended as Annex "A-1" and is hereby made an integral part of this Rule.

The succeeding capex applications shall be filed by DUs falling under Group 1, 3, and 5, on the first quarter of the year before the start of the next 3-year period capex application, while capex applications of Group 2, 4, and 6 shall be filed on the 3rd quarter of the year before the start of the next 3-year period capex application.

Capital Expenditure Projects involving joint ventures/consortium of Distribution Utilities or Regulated Entities shall be filed one (1) year before the project is implemented through a joint application by the concerned Regulated Entity.

3.2 Requirements for Filing the Application of Capital Expenditure Program

3.2.1  Filing Requirements

A Regulated Entity shall submit to ERC a network assets capital expenditure program for a period of three (3) years. The periodic filing of these proposed capital expenditure projects involving the acquisition, improvement and installation of distribution plant assets enumerated in Section 2.1.1 shall be made for review and approval of the ERC. Proposed capital projects must be classified in accordance with Article II. This expenditure program also includes the capital projects that form part of the system loss reduction program. CHDAEc

The three (3)-year capital expenditure program shall be consistent with the five (5)-year rolling DDP submitted by the Regulated Entity to the DOE.

The application for the approval of the three (3)-year capital expenditure program shall be verified by an authorized representative of the Regulated Entity, which has to present either a Board Resolution or Secretary's Certificate to show proof of his/her designation as a representative of the Board of Directors and shall be filed with the ERC together with properly labeled three (3) hard copies and three (3) electronic copies. The capital expenditure program shall be accompanied by the following documents:

3.2.1.1  Description of each capital project;

3.2.1.2  Type of the projects in accordance with Section 2.5;

3.2.1.3  Project Justifications (include the adverse effects of the non-implementation of the proposed Project(s) and Impact or benefits of the proposed Project(s) on the system);

3.2.1.4  Options/Alternatives considered in lieu of the proposed Project(s) with corresponding analyses of advantages/disadvantages of each option. TcHEaI

3.2.1.5  Regulated Entity's Distribution Development Plan;

3.2.1.6  Technical Analysis 2 (commercial software load flow simulation and interpretation of results showing the electrical effects of the proposed project/s such as power transformer loadings, voltage drop, power quality, power factor, system loss, frequency, harmonics, load/phase balancing etc.);

3.2.1.7  Projected Financial & Economic Cost Analysis;

i. Rate impact study of the proposed Projects (include the monetary benefits that can be delivered or derived upon pursuing the proposed projects;

ii. Net Present Value, Internal Rate of Return and Benefit/Cost Ratio analysis (include analysis for the alternatives);

iii. 5-year Projected Financial Ratios:

(a) Liquidity

(b) Efficiency

(c) Profitability

(d) Leverage, and

(e) Other ratios as determined by the ERC.

3.2.1.8  Conceptual Engineering Design and Drawings;

3.2.1.9  Project Cost Estimates which has to be in reference to the submitted engineering design and bill of materials;

3.2.1.10 Project Financing Plan 3 (the CAPEX fund, in the case of Electric Cooperatives, shall be utilized to finance the proposed capital expenditure projects and also for the payment of amortization in the case of project financing loans); cDCSET

3.2.1.11 Gantt Chart Schedule of the proposed capital expenditure projects;

3.2.1.12 Board Resolution or Secretary's Certificate approving the proposed Projects;

3.2.1.13 Sworn Statement from the authorized representative of the Regulated Entity that an application for approval from the concerned agencies that may have interest in the proposed project has been filed/or shall be filed by the Regulated Entity (specify date of filing and furnish ERC a copy within five (5) days upon filing);

3.2.1.14 Proof/s that public information dissemination of the proposed capital expenditure program was conducted by the Regulated Entity. At the minimum, the Regulated Entity should show proof of posting in at least three conspicuous places within its franchise area, of a notice containing the following: 1) the proposed projects; 2) the reasons for proposing said projects; 3) the source of fund for the said projects; and 4) indicative rate impact of the said projects, if any; and

3.2.1.15 Proof that a separate application for authority to secure loan has been filed with the ERC in the case of projects to be funded by loan/standby credit. Approval to secure loans sourced from NEA may be filed together with the capex application.

Subsequent filing of capital expenditure applications shall be based on the capital expenditure projects as indicated in the rolling DDP submitted by the Regulated Entity. EDCIcH

Any petition, application or action to be filed herein shall be governed by the provision of other application as provided for in the ERC Rules of Practice and Procedure, the pertinent provisions of the Act or its IRR and other related laws.

3.2.2  Project Justification Templates 4

For purposes of uniformity, a project justification form or template is provided herewith and shall be accomplished upon filing of the proposed capital projects. Content of this template is discussed below.

Project Details:

a) Name and Code: A unique project code and project name must be provided for each project. These details will be used in all future consideration of or communication about a particular project. IHCDAS

b) Description: A short description of the project must be provided, which will allow the ERC to understand the scope and location of the project.

c) Commissioning Date: The required commissioning date for the project should be indicated (month, year). Where projects are to be commissioned in phases, these dates are to be separately indicated.

Project Classification:

b) Rank: The project ranking should be indicated, based on the assessment of the Regulated Entity. This ranking can either be a 1st priority (projects deemed essential) or a 2nd priority (projects deemed important but not critical).

c) Project Driver Classification: The project driver should indicate the main driver for the project. (Where a project has more than one driver, the dominant one should be indicated.) Five categories of project drivers are to be considered load growth; network non-growth; network control/safety/metering; non-network; and statutory.

d) Project Type Classification: The project type classification indicates the type of project, classed in one of three categories renewal; refurbishment; and growth.

e) Expenditures for 3-year period: The required forex and local amount of expenditures for the project should be indicated. The total expenditures should be in million pesos. aAEIHC

Project Need:

a) Project Purpose: A brief objectives of the project must be provided, which will allow the ERC to understand the purpose of the project.

b) Impact if Project Not Implemented: A brief statement of the effects of the project must be provided, which will allow the ERC to understand the impact if project is not implemented.

c) Reason for Ranking Project Commissioning Date Relative to Other Projects: A reason for ranking the project must be provided, which will allow the ERC to understand the importance of prioritizing the project.

Project Cost Estimate:

a) Item: A list of equipment/materials used in the project must be provided, which will allow the ERC to understand the itemized breakdown of quantity, labor and material cost of the project.

b) Estimated Cash Flow per Year: The estimated cash flow per year of the project must be provided, which will allow the ERC to understand the yearly capital outlay. The indicative cost per design phase should also be shown. EHACcT

c) Technical Description: A technical brief of the project must be provided, which will allow the ERC to understand the technical aspects of the projects.

Project Performance Measure:

a) Qualitative Performance Measures: Indicate the parameter under consideration with corresponding performance results for without the project and with project.

b) Quantitative Performance Measures: Indicate the parameter under consideration with corresponding annual numerical performance values for without the project and with project.

Project Capital Expenditure Summary:

a) Regulated Distribution Services Asset: Indicate the actual historical and forecast cost of networks assets for the period being considered in the application.

b) Distribution Connection Services Asset: Indicate the actual historical and forecast cost of distribution connection assets for the period being considered in the application.

3.3 Force Majeure or Fortuitous Event Capital Expenditure

If a Force Majeure or Fortuitous event, as the case may be, occurs, the affected Regulated Entity shall seek the ERC's confirmation of the implementation of capital expenditure projects arising from such event.

To seek the ERC's confirmation, the affected Regulated Entity must give the ERC a Force Majeure or Fortuitous Event Notice within three (3) months from the occurrence of the Force Majeure or Fortuitous Event and must specify the following:

(a) details of the Force Majeure or Fortuitous Event concerned;

(b) the details of capital expenditures that the affected Regulated Entity has actually incurred as of the date of Force Majeure or Fortuitous Event:

(i) in the distribution of electricity to Connection Points in respect of the relevant Regulated System; and

 

(ii) in connection with the provisions of any legislation, or of rules, regulations or guidelines made under the EPIRA, including the IRR, the Grid Code and the Distribution Code, which must be complied with in relation to the distribution of such electricity.

The Force Majeure or Fortuitous Event Notice must be accompanied by evidence of the increase in costs referred to in paragraph (b) and justification that such costs are reasonable and occur as a sole consequence of the FM or FE.

The affected Regulated Entity shall file a formal application within thirty (30) days from the submission of the Force Majeure or Fortuitous Event Notice and shall be decided by the ERC within sixty (60) days from the time the applicant formally offers its evidence. The formal application shall be supported by documents indicating the following:

a) Project Description;

b) Justifications or Benefits to be delivered;

c) Estimated Project Costs;

d) Project Financing Plan; and

e) Project Schedule.

3.4 Emergency Capital Expenditure

These are capital expenditure projects that require immediate implementation during an event other than those enumerated and covered in the definition of a force majeure, or fortuitous event in order to maintain safe, reliable, secure and efficient operation of the power system. These projects shall be filed with ERC for approval within sixty (60) days after the start of construction and shall be supported by documents indicating the following:

a) Project Description; IESAac

b) Justifications or Benefits to be delivered;

c) Estimated Project Costs;

d) Project Financing Plan; and

e) Project Schedule.

3.5 Unplanned Capital Expenditure

These are expenditure projects that may occur at any given period which may be resulting from unexpected significant new load that will be connected to the Distribution System. A Regulated Entity shall file a formal application prior to the start of implementation of such projects and shall be supported by documents similar to the usual requirements of network asset capital expenditures.

3.6 Contingency Capital Expenditure

These are expenditures that may occur at any given period which may be resulting from the implementation of national government policies and initiatives and/or implementation of local government development programs. A Regulated Entity shall file a formal application sixty (60) days from the start of implementation of such projects and shall be supported by documents indicating the following:

a) Project Description;

b) Justifications or Benefits to be delivered;

c) Estimated Project Costs;

d) Project Financing Plan; and aCSTDc

e) Project Schedule.

ARTICLE IV

Evaluation and Approval of the Application

4.1 Evaluation of Capital Expenditure Program

Before accepting the application for filing, the ERC's Docket Section may first refer applicant or its representative to the appropriate Service of the ERC for a pre-filing conference to inquire into the completeness of the supporting documents attached to the application.

The application may be rejected due to non-payment of the required filing fee as docketing requirement. Rejection of such application is not a bar to the re-filing of the same with the ERC.

The ERC may conduct an ocular inspection before the hearing without prejudice to the conduct of additional inspection, if necessary, to verify/clarify any issue or information pertaining to the proposed capital projects. EICDSA

During the review and evaluation, the ERC may request additional information from the Regulated Entity on issues that it requires more clarification pertaining to their capital expenditure program.

Failure on the part of the Regulated Entity to submit any of the required detail/information within the prescribed period from receipt of an Order shall be a ground for the denial of the application.

Any application for the approval of any capital expenditure project shall be decided by the ERC within ninety (90) days from the time the case was declared submitted for resolution.

The ERC may refer to the DMC or engage the services of a consultant at a reasonable cost, in the evaluation of any Capital Projects application submitted to it for approval. The concerned Regulated Entity shall be charged an amount equivalent to the expenses incurred by the ERC in engaging the services of the consultant, and said expenses, shall be recovered by the concerned Regulated Entity as part of the capital expenditure of the project being evaluated. TIEHDC

4.2 Payment of Fees

For the authorization and approval of capital expenditure projects, a Regulated Entity shall be required to pay a permit fee based on the existing schedule of ERC Fees and Charges.

Payment of permit fee shall be on an annual basis. The amount of permit fee to be paid shall correspond to the estimated cash flow per year of the project. The first of the series of payments shall be made fifteen (15) days from receipt of the Decision approving the application. The succeeding annual payments shall be paid every 15th day of January of the pertinent year.

ARTICLE V

Monitoring of Capital Expenditure Implementation

5.1 Reportorial Requirements

A Regulated Entity shall submit the results of the competitive bidding which shall include proposals and purchase orders, the as-built drawings and bill of materials and the actual cost incurred in the implementation of the planned capital expenditure projects not later than the 1st working week of January of the succeeding year. TCaEIc

The current DDP shall also be submitted annually not later than the last week of April for monitoring of the planned capital expenditure projects of a Regulated Entity.

A Regulated Entity must also notify the ERC, in writing, if any expenditure for a Capital Project forecasted to be undertaken in the three (3)-year capital expenditure program as approved by the ERC, has not been substantially undertaken within twelve (12) months from the time it was so forecasted to be undertaken. The written report shall state the reason/s for such deferment and the updated status of the said deferred capital projects, i.e., if the projects will be deferred indefinitely or will it be included in the next filing of capex application.

A Regulated Entity shall not be required to file formal application for ERC approval of capital expenditures considered as distribution connection assets and non-system assets. However, the Regulated Entity must submit to the ERC in writing on or before March 30th of each year, an annual report for the previous year's capital expenditure projects implemented for distribution connection assets and non-system assets. The written report shall state the need and description of the project or activity that were implemented including the benefits and the actual costs incurred. The qualitative performance measures shall be included in the report. THIECD

5.2 Regulatory Inspection

The ERC may conduct site inspections anytime without notice to the Regulated Entity to verify and monitor the progress of the proposed capital projects being implemented. The Regulated Entity shall provide the ERC inspection team of the project records, documents, any variation order and relevant reports necessary in the assessment of the capital expenditure programs undertaken, in accordance with the prescribed format.

ARTICLE VI

Final Provisions

6.1 Administrative Sanctions

Violations of these Rules shall be subject to the imposition of fines and penalties in accordance with the Guidelines to Govern the Imposition of Administrative Sanctions in the Form of Fines and Penalties pursuant to Section 46 of the EPIRA. HIACac

6.2 Transitory Provision

The initial capex application shall be filed simultaneously on or before April 30, 2009 as follows:

Group	Period	Year
1	3 years	2009 to 2011
2	3 years	2009 to 2011
3	4 years	2009 to 2012
4	4 years	2009 to 2012
5	5 years	2009 to 2013
6	5 years	2009 to 2013

Thereafter, the proposed three (3) year capital expenditure projects as indicated in the rolling DDP of the Regulated Entity shall be filed for approval in accordance with Section 3.1.

Capital projects which have already been included in the applicant's rate base, as approved by the ERC, or those that were already filed for evaluation, or those that were already filed for inclusion in the rate base and presently being evaluated by the ERC, shall be excluded from the application of these Rules.

6.3 Separability Clause

If for any reason, any provision of these Rules is declared unconstitutional or invalid by final judgment of a competent court, the other parts or provisions hereof which were not affected thereby shall continue to be in full force and effect.

6.4 Repealing Clause

Any rule or regulation inconsistent with the provisions of these Rules is hereby repealed and modified accordingly. aCIHAD

6.5 Effectivity

These Rules shall take effect fifteen (15) days upon its publication in a newspaper of nationwide circulation.

Pasig City, December 15, 2008.

(SGD.) ZENAIDA G. CRUZ-DUCUTChairperson

(SGD.) RAUF A. TANCommissioner

(SGD.) ALEJANDRO Z. BARINCommissioner

(SGD.) MARIA TERESA A.R. CASTAÑEDACommissioner

(SGD.) JOSE C. REYESCommissioner

ANNEX A-1

GROUPINGS OF REGULATED ENTITY (DISTRIBUTION UTILITIES)

Group 1 — First Semester (Year 1)

1. Abra Electric Cooperative, Inc. (ABRECO)

2. Benguet Electric Cooperative, Inc. (BENECO)

3. Central Pangasinan Electric Cooperative, Inc. (CENPELCO)

4. Ilocos Norte Electric Cooperative, Inc. (INEC)

5. Ilocos Sur Electric Cooperative, Inc. (ISECO)

6. La Union Electric Cooperative, Inc. (LUELCO)

7. Mt. Province Electric Cooperative, Inc. (MOPRECO)

8. Pangasinan I Electric Cooperative, Inc. (PANELCO I)

9. Pangasinan III Electric Cooperative, Inc. (PANELCO III)

10. Batanes Electric Cooperative, Inc. (BATANELCO)

11. Cagayan I Electric Cooperative, Inc. (CAGELCO I)

12. Cagayan II Electric Cooperative, Inc. (CAGELCO II)

13. Ifugao Electric Cooperative, Inc. (IFELCO)

14. Isabela I Electric Cooperative, Inc. (ISELCO I)

 

15. Isabela II Electric Cooperative, Inc. (ISELCO II)

16. Kalinga Apayao Electric Cooperative, Inc. (KAELCO)

17. Nueva Vizcaya Electric Cooperative, Inc. (NUVELCO)

18. Quirino Electric Cooperative, Inc. (QUIRELCO) SCEDAI

Group 2 — Second Semester (Year 1)

1. Aklan Electric Cooperative, Inc. (AKELCO)

2. Antique Electric Cooperative, Inc. (ANTECO)

3. Capiz Electric Cooperative, Inc. (CAPELCO)

4. Central Negros Electric Cooperative, Inc. (CENECO)

5. Guimaras Electric Cooperative, Inc. (GUIMELCO)

6. Iloilo I Electric Cooperative, Inc. (ILECO I)

7. Iloilo II Electric Cooperative, Inc. (ILECO II)

8. Iloilo III Electric Cooperative, Inc. (ILECO III)

9. Negros Occidental Electric Cooperative, Inc. (NOCECO)

10. Victoria Rural Electric Service Cooperative, Inc. (VRESCO) cIETHa

11. Bantayan Island Electric Cooperative, Inc. (BANELCO)

12. Bohol I Electric Cooperative, Inc. (BOHECO I)

13. Bohol II Electric Cooperative, Inc. (BOHECO II)

14. Cebu I Electric Cooperative, Inc. (CEBECO I)

15. Cebu II Electric Cooperative, Inc. (CEBECO II)

16. Cebu III Electric Cooperative, Inc. (CEBECO III)

17. Camotes Electric Cooperative, Inc. (CELCO)

18. Negros Oriental I Electric Cooperative, Inc. (NORECO I)

19. Negros Oriental II Electric Cooperative, Inc. (NORECO II)

20. Province of Siquijor Electric Cooperative, Inc. (PROSIELCO)

Group 3 — First Semester (Year 2)

1 Biliran Electric Cooperative, Inc. (BILECO) AScHCD

2. Eastern Samar Electric Cooperative, Inc. (ESAMELCO)

3. Leyte I Electric Cooperative, Inc. (LEYECO I)

4. Leyte II Electric Cooperative, Inc. (LEYECO II)

5. Leyte III Electric Cooperative, Inc. (LEYECO III)

6. Leyte IV Electric Cooperative, Inc. (LEYECO IV)

7. Leyte V Electric Cooperative, Inc. (LEYECO V)

8. Northern Samar Electric Cooperative, Inc. (NORSAMELCO)

9. Samar I Electric Cooperative, Inc. (SAMELCO I)

10. Samar II Electric Cooperative, Inc. (SAMELCO II)

11. Southern Leyte Electric Cooperative, Inc. (SOLECO)

12. Basilan Electric Cooperative, Inc. (BASELCO)

13. Cagayan de Sulu Electric Cooperative, Inc. (CASELCO) CcAIDa

14. Siasi Island Electric Cooperative, Inc. (SIASELCO)

15. Sulu Electric Cooperative, Inc. (SULECO)

16. Tawi-Tawi Electric Cooperative, Inc. (TAWELCO)

17. Zamboanga Sur I Electric Cooperative, Inc. (ZAMSURECO I)

18. Zamboanga Sur II Electric Cooperative, Inc. (ZAMSURECO II)

19. Zamboanga City Electric Cooperative, Inc. (ZAMCELCO)

20. Zamboanga Norte Electric Cooperative, Inc. (ZANECO)

Group 4 — Second Semester (Year 2)

1. Agusan del Norte Electric Cooperative, Inc. (ANECO)

2. Agusan Sur Electric Cooperative, Inc. (ASELCO)

3. Bukidnon II Electric Cooperative, Inc. (BUSECO)

4. Camiguin Island Electric Cooperative, Inc. (CAMELCO)

5. Dinagat Electric Cooperative, Inc. (DIELCO)

6. First Bukidnon I Electric Cooperative, Inc. (FIBECO)

7. Misamis Occidental I Electric Cooperative, Inc. (MOELCI I)

8. Misamis Occidental II Electric Cooperative, Inc. (MOELCI II)

9. Misamis Oriental I Electric Cooperative, Inc. (MORESCO I)

10. Misamis Oriental II Electric Cooperative, Inc. (MORESCO II)

11. Siargao Island Electric Cooperative, Inc. (SIARELCO)

12. Surigao Norte Electric Cooperative, Inc. (SURNECO) cICHTD

13. Albay Electric Cooperative, Inc. (ALECO)

14. Camarines Norte Electric Cooperative, Inc. (CANORECO)

15. Camarines Sur I Electric Cooperative, Inc. (CASURECO I)

16. Camarines Sur II Electric Cooperative, Inc. (CASURECO II)

17. Camarines Sur III Electric Cooperative, Inc. (CASURECO III)

18. Camarines Sur IV Electric Cooperative, Inc. (CASURECO IV) ITESAc

19. First Catanduanes Electric Cooperative, Inc. (FICELCO)

20. Masbate Electric Cooperative, Inc. (MASELCO)

21. Sorsogon II Electric Cooperative, Inc. (SORECO I)

22. Sorsogon I Electric Cooperative, Inc. (SORECO II)

23. Ticao Island Electric Cooperative, Inc. (TISELCO)

Group 5 — First Semester (Year 3)

1. Aurora Electric Cooperative, Inc. (AURELCO)

2. Nueva Ecija I Electric Cooperative, Inc. (NEECO I)

3. Nueva Ecija II (Area 2) Electric Cooperative, Inc. (NEECO II)

4. Nueva Ecija III Electric Cooperative, Inc. (NEECO III)

5. Pampanga I Electric Cooperative, Inc. (PELCO I)

6. Pampanga II Electric Cooperative, Inc. (PELCO II)

7. Pampanga III Electric Cooperative, Inc. (PELCO III)

8. Peninsula Electric Cooperative, Inc. (PENELCO)

9. Pampanga Rural Service Electric Cooperative, Inc. (PRESCO)

10. San Jose City Electric Cooperative, Inc. (SAJELCO)

11. Tarlac II Electric Cooperative, Inc. (TARELCO I)

12. Tarlac II Electric Cooperative, Inc. (TARELCO II) cEaCAH

13. Zambales I Electric Cooperative, Inc. (ZAMECO I)

14. Zambales II Electric Cooperative, Inc. (ZAMECO II)

15. Davao Norte Electric Cooperative, Inc. (DANECO)

16. Davao Sur Electric Cooperative, Inc. (DASURECO)

17. Davao Oriental Electric Cooperative, Inc. (DORECO)

18. South Cotabato I Electric Cooperative, Inc. (SOCOTECO I)

19. South Cotabato II Electric Cooperative, Inc. (SOCOTECO II)

20. Surigao Sur I Electric Cooperative, Inc. (SURSECO I)

21. Surigao Sur II Electric Cooperative, Inc. (SURSECO II)

Group 6 — Second Semester (Year 3)

1. North Cotabato Electric Cooperative, Inc. (COTELCO)

2. Lanao del Norte Electric Cooperative, Inc. (LANECO)

3. Lanao del Sur Electric Cooperative, Inc. (LASURECO) ICHcTD

4. Maguindanao Electric Cooperative, Inc. (MAGELCO)

5. Sultan Kudarat Electric Cooperative, Inc. (SUKELCO)

6. Batangas I Electric Cooperative, Inc. (BATELEC I)

7. Batangas II Electric Cooperative, Inc. (BATELEC II)

8. Busuanga Electric Cooperative, Inc. (BISELCO)

9. First Laguna Electric Cooperative, Inc. (FLECO)

10. Lubang Electric Cooperative, Inc. (LUBELCO)

11. Marinduque Electric Cooperative, Inc. (MARELCO)

12. Occidental Mindoro Electric Cooperative, Inc. (OMECO)

13. Oriental Mindoro Electric Cooperative, Inc. (ORMECO)

14. Palawan Electric Cooperative, Inc. (PALECO) ESTDcC

15. Quezon I Electric Cooperative, Inc. (QUEZELCO I)

16. Quezon II Electric Cooperative, Inc. (QUEZELCO II)

17. Romblon Electric Cooperative, Inc. (ROMELCO)

18. Tablas Island Electric Cooperative, Inc. (TIELCO)

19. Local Government Unit Owned-and-Operated Distribution Systems;

20. Qualified Third Parties (QTPs) operating in waived areas of a franchised Distribution Utility; and

21. Consortium of Distribution Utilities

ANNEX A-2

JUSTIFICATION FOR CAPITAL PROJECTS

 

Technical description:(Attach single line diagrams, construction sketches, route drawings, etc. as appropriate)

Note: Utilities should attach their own detailed cost estimates if this format is not appropriate for a particular project

QUALITATIVE PERFORMANCE MEASURES

Performance Measures With or Without the Project:

	Result Without	Result With
Parameter Under Consideration	the Project	Project
_____________________________	________________	______________
_____________________________	________________	______________
_____________________________	________________	______________

 

QUANTITATIVE PERFORMANCE MEASURES

Performance Measures With or Without the Project:

 

Template : Summary of Capital Expenditure (total, expressed in PhP)

 

Footnotes

1. These qualify when the Regulated Entity expects to use them during more than one period: If the spare parts or servicing equipment can be used only in connection with an item of property, plant and equipment and their use is expected to be irregular, they are accounted for as property, plant and equipment and are depreciated over a time period not exceeding the useful life of the related asset.

2. Updated System Loss segregation data shall be included together with other parameters deemed relevant in the conduct of the technical analysis.

3. In the case of project financing loans, the cost of money should not be greater than the prevailing market rate.

4. See Annex "A-2" — Justification for Capital Project. DHcSIT