Bangladesh Energy Regulatory Commission (BERC)

Anchor Tower , 7 th Level,1/1B, Sonargaon Road

Dhaka-1205, Bangladesh

88-02-9666323

The Bangladesh Energy Regulatory Commission in exercise of the power conferred by the Bangladesh Energy Regulatory Commission Act, 2003 (Act No 13 of 2003) as amended, hereby adopts the following regulation.

1. SHORT TITLE AND COMMENCEMENT:

a. This regulation shall be called Bangladesh Energy Regulatory Commission Gas Distribution Tariff Regulation, 2008.

b. This regulation shall come into force upon publication in the official Gazette.

2. SCOPE AND APPLICATION:

a. This regulation shall define: (1) the process of submitting application by a Licensee for a tariff containing the rate, terms, and conditions of service, or a change thereof; (2) the methodology to be used by the Commission in reviewing the application; (3) and the procedures for the issuance of an approved tariff of the applicant licensee; or an approved change thereof.

b. This Regulation shall apply to licensed applicants supplying natural gas distribution services.

c. In developing this regulation, the Commission has taken into consideration applicable acts, orders, etc.

3. DEFINITIONS:

a. Words, terms and phrases that are defined in the Bangladesh Energy Regulatory Commission Act, 2003 (Act No 13 of 2003), including subsequent amendments to the Act, and Commission's Regulations, shall have the same meaning for the purposes of this Natural Gas Distribution Tariff Regulation, 2007.

b. Words, terms and phrases that are not defined in this Regulation or in the Bangladesh Energy Regulatory Commission Act, 2003 (Act No 13 of 2003), including subsequent amendments to the Act and Commission's Regulations, shall have the meaning assigned to them in or other applicable legislation. Words, terms and phrases that are not defined in either the Bangladesh Energy Regulatory Commission Act, 2003 (Act No 13 of 2003), including subsequent amendments to the Act, and the Regulations, shall be defined by the Commission as needed.

c. Unless the context requires otherwise, the words, terms and phrases in the Natural Gas Distribution Tariff Regulation and any attachments hereto shall have the following meanings:

(1) “Acceptance Date” means the date on which a tariff application has been received with required data by the Commission, and the process for hearing commences.

(2) “ Accounts" means the accounts prescribed in the uniform system of accounts.

(3) “Act” means the Bangladesh Energy Regulatory Commission Act, 2003 (Act No 13 of 2003) including any subsequent amendments.

(4) “Affiliate” means an entity in the same corporate family of a distribution provider that buys, sells, trades or administers energy in Bangladesh , including entities engaged in financial energy transactions relating thereto.

(5) “Amortize” means to spread a nonrecurring expenditure over a period of years to avoid distortion or unfair impact in rate design.

(6) “Applicant” means a licensed entity who applied to the Commission in accordance with this Regulation to establish tariffs for operations by the licensee.

(7) “Beta” means a measure of market risk used with the capital asset pricing model to capture the extent a stock's return moves with the general stock market return, or the best estimate of measure.

(8)“Block Rate” means a rate schedule which provides different unit charges for successive blocks or amounts of units consumed.

(9) “Calorimeter” means equipment used to test the heating value of natural gas.

(10) “Capacity” means the load for which the system is rated.

(11) “Capacity Factor” means the degree to which the facilities and invested capital are being used.

(12) “Capital Asset Pricing Model” means a method of measuring the cost of capital which assumes the expected return on equity is equivalent to that on a riskless interest rate plus a risk premium.

(13) “City Gas” a location at which gas control passes from a natural gas pipeline to a local distribution licensee.

(14) “Common Carrier” means a transporter obligated to provide transportation service to an interested party without taking title to the commodity.

(15) “Commission” means the Bangladesh Energy Regulatory Commission.

(16) “Comparable Earnings” means a measurement of the rate of return by comparing one company's earnings with others.

(17) “Compressor Station” means an facilities which supply the energy to move natural gas at increased pressure from fields, through transmission systems, through distribution systems, or into storage systems.

(18) “Condensate (lease condensate): A natural gas liquid recovered from associated and non-associated gas wells from lease separators or field facilities. In Bangladesh this is primarily composed of High Speed diesel (HSD), Light Diesel Oil (LDO), and Motor Spirit (MS).

(19) “Construction (Capital) Work in Progress (CWIP)” means plant not yet operational which may or may not be included in a licensee's rate or asset base.

(20) “Distribution Companies” mean regulated licensees which directly market natural gas to consumers on a retail basis.

(21) “Effective Date” means the date on which a proposed tariff schedule with rates is permitted by the Commission to become effective.

(22) “Force Majeure” means any acts of God, wars or insurrections, civil disturbances, breakage of machinery or pipes, necessity for repair, insufficiency of natural gas supply, order of any government authority, or any other cause not within the control of the Distribution utility.

(23) “Gas Main” means a distribution line that serves as a common source of supply for gas service lines.

(24) “Initial Rate” means a filed rate or rates applicable to the Distribution of natural gas other than that which proposes to supersede, supplement, cancel or otherwise change the provisions of a tariff rate schedule currently on file with this Commission.

(25) “Interruptible Rates” means rates offered to large industrial and commercial customers to have their service interrupted, based upon the distribution utility's request.

(26) “Liquefied Natural Gas (LNG)” means natural gas that has been cooled for storage or shipment as a liquid.

(27) “Load Factor” means the degree to which a natural gas distribution system is being used – the ratio of average distribution to peak distribution volume.

(28) “Net Utility Plant” means the investment in utility plant less accumulated depreciation.

(29) “Person(s) means an individual or entity.

(30) “Rate” means the authorized charges, per distributed unit for a specified time period for any of the classes of distribution licensee services provided to a customer.

(31) “Rate of Return” means the return earned or allowed to be earned by a licensee calculated as a percentage of its rate base.

(32) "Regulations" means any regulations developed and promulgated by the Commission according to the Bangladesh Energy Regulatory Commission Act, 2003 (Act No 13 of 2003), including subsequent amendments to the Act.

(33) “Salvage Value" means the amount received for property retired, less any expenses incurred in connection with the sale or in preparing the property for sale; or, if retained, the amount at which the material recoverable is chargeable to materials and supplies or other appropriate account.

(34) “Schedule” means a statement of the pricing format of natural gas distribution, and the terms and conditions governing its applications.

(35) “Service Obligation” means the obligations which are among the duties a licensee must perform, for example, to serve all customers; to provide adequate service; and to render safe, efficient, and nondiscriminatory service.

(36).”Staff” means officers and employees employed at the Commission to assist the Commission in carrying out its functions.

(37) “Tariff” means a document, approved by the Commission, listing the terms and conditions of service and a schedule of rates, under which licensee services will be provided.

(38) “Terms and Conditions of Service” means a published document included as part of a licensee's tariff that establishes the licensee's terms and conditions for providing service to a customer, discussing such issues as the conditions under which connection will be provided to a customer, metering, payment instructions, etc.

(39) “Transmission” means an interconnected pipes and associated equipment for the transportation of natural gas from the production gathering system of individual fields to town border stations, city gates, or large volume off-take meters and valves for delivery to customers, or delivered to other natural gas systems.

(40) “Transmission Provider” means any Licensee that owns, operates or controls assets used to transport bulk natural gas.

(41) “Unaccounted Gas” means the quantity difference between the receipts of gas to the distribution system; and the total gas booked as sales, net interchange, and licensee use.

(42) “Uniform System of Accounts” means a system of financial accounts prescribed by the BERC for use by the licensees under its jurisdiction.

(43) “Working Capital” means the amount of cash required to operate a licensee during the average interim period between the rendition of the service and the receipt of payment for the service.

4. APPLICATION FORM AND FEES:

a. An application for the filing of initial, or the changing of current effective distribution tariff, shall be filed with the Bangladesh Energy Regulatory Commission in accordance with this regulation.

b. An application shall be made upon payment of an application fee, which will be fixed by the Commission from time to time. The application fee shall be paid by means of demand draft/pay order from a schedule bank in Bangladesh , in the name of the Bangladesh Energy Regulatory Commission.

5. DOCUMENTS TO ACCOMPANY A TARIFF APPLICATION:

a. The filing of an application for a tariff with rates, and terms and conditions of service shall include the following:

(1) A list of documents submitted with the filing;

(2) The date on which service under the proposed schedule is expected to commence;

(3) The names and addresses of those whom the tariff schedule will be mailed;

(4) A copy of the draft notice announcing the rate;

(5) A brief description of the kinds of services to be furnished and the rates specified therein for each service;

(6) A summary of the circumstances which show that all requisite agreement to the tariff schedule or to the filing thereof, including any contract embedded therein, has in fact, been obtained;

(7) Estimates of the transactions and revenues under a tariff schedule;

(i) This shall include estimates by months and for the year, of the quantities of services to be rendered and of the revenues to be derived during the twelve months immediately following the month in which those services will commence.

(ii) Such estimates should be divided by class of customer, and delivery points and shall show all billing determinants.

(8) The basis of the rate proposed in a tariff schedule and an explanation of how the proposed rate was derived;

(9) A summary statement of all costs (whether fully distributed, incremental or other) computations involved in arriving at the derivation of the level of the rate in sufficient detail to justify the rate, shall be submitted with the filing;

(10) A comparison of the proposed rate with other rates of the filing utility or regulated entity for similar distribution service, interconnection, and ancillary services.

(11) A copy of relevant distribution, ancillary service and interconnection agreements, including detailed terms of service.

b. The required documentation, in support of a change to an existing tariff schedule, is as follows:

(1) Summary of tariff proposal with historical trend of the rate;

(2) Justification of tariff changes proposal;

(3) Detailed methodology of arriving at the proposed tariff rate;

(4) List of person(s) likely to be affected by the changes in the tariff;

(i) The current relationship with the person(s);

(ii) The relationship that will emerge after the proposed change.

(5) A copy of the draft notice announcing the change in the tariff.

(6) Audited annual accounts for the last consecutive three years;

(7) Provisional accounts for the current year at the time of submission;

(8) Comparative statement of present and future financial position resulting from changes in tariff;

(9) Details of financial impact if the proposal is not approved;

(10) Financial forecast for the next year at the time of filing of the tariff proposal;

(11) A three year historical loss report;

(12) Any other information which the applicant considers could be useful for evaluating the proposal, including detailed terms of service.

c. All accounting codes utilized in the application for an initial rate or change in existing tariff rate schedule shall be consistent with the Commission's uniform system of accounts, as and when published.

d. All application filings should provide five copies in printed form and a copy of the filing in an electronic format, preferably Microsoft Word, Excel, and Access.

e. Commission may seek clarification or new information relevant to the proposal after submission of the proposal.

6. ACCEPTANCE AND PROCESSING OF APPLICATION:

a. Acceptance of Application.

(1) The Staff of the Commission has thirty days from the receipt of the application by the Commission Secretary to review and identify any flaws in the application, and any additional information that the Commission may require, in evaluating the application.

(2) The Staff shall establish a data request deadline, not to exceed two weeks, within which the applicant will provide the supplemental information.

(3) Upon receipt of the required information, the Staff will prepare an entry for acceptance by the Commission, at a regularly scheduled Commission administrative meeting, accepting the application for consideration. That acceptance date becomes the official receipt date for the application.

(4) The fact that the Commission accepts a tariff schedule or any part for filing shall not constitute approval by the Commission of such tariff schedule or part thereof.

(5) The Commission shall not be required to entertain or accept any application until such supporting supplemental data is furnished.

(6) The Commission shall not pass an order rejecting the application without giving the applicant an opportunity of being heard or making a written representation.

(7) If the Commission accepts the application, it may give such orders and directions for the service of notices as it deems appropriate to –­

(a) all persons affected by, or interested in, the application who in the opinion of the Commission are likely to be affected or interested; and

(b) persons, who, by reason of their calling or expertise, may be of assistance to the Commission in arriving at a just and informed determination on the application.

b. Publication and Service of Notice.

(1) A notice issued on the directions of the Commission may be served on the party concerned, as the Commission may direct, and the Commission may direct the service to be effected through any one or more of the following modes of service, namely:

­

(i) by hand delivery through a messenger;

(ii) by registered post with an acknowledgment due; or

(iii) by publication in one English language and one Bangla language national daily newspaper, and by advertisement in the electronic media in cases where the Commission is satisfied that it is not reasonably practicable to serve notices in any other manner.

(2) Every notice or process required to be served on, or delivered to, any person may be sent to the person at the address furnished by him for service, or at the place where the person or his agent ordinarily resides or conducts business or personally works for gain

When a person is to be served during the course of the proceedings and such person has authorized in writing an agent or representative to represent him in the proceedings, such agent or representative shall be considered duly authorized to accept service of a notice and process on behalf of the person concerned.

(3) The Commission will issue notice of filing to the public by publication in one English language and one Bangla language national daily newspaper or on the Commission's website.

c. Processing of Application:

(1) The processing of a tariff application shall begin when the application is officially accepted by the Commission and registered with the Secretary of the Commission. A date stamp shall be put on first page of the Application. An appropriate receipt for the application fee shall be prepared and provided to the Applicant.

(2) All paperwork pertaining to a tariff application shall be maintained by the Commission in a separate case file for each applicant. The Commission shall maintain a registration log of all orders issued and this information, including Commission's resolutions, shall be available to the public for review by any interested parties, with exception of the information defined as confidential according to Commission Regulations or written order. Copies of the application, Commission order, and all written testimony and transcripts of oral testimony given in a hearing shall also be filed in this case.

7. EVALUATION OF THE APPLICATION:

a. The Commission shall evaluate the respective application once it has been accepted. The application shall be evaluated in accordance with published Commission tariff methodology.

b. The Commission may perform investigations to collect necessary information, and generally take any measure or action it considers necessary to decide whether or not to approve such an application.

8. REJECTION OF APPLICATION:

a. The Commission may reject an application for any reasons that include, but are not limited to, the following:

(1) The enclosed documents to the application do not comply with the requirements of this tariff regulation and/or the applicant has not filed supplemental information pursuant to a request for data from Commission Staff within the required filing deadline, or the application violates other applicable laws of Bangladesh;

(2) The submitted documents contain materially incorrect information;

(3) The applicant does not have a right to request the tariff change under the Act, this Tariff Regulation and any other Regulations issued by the Commission.

b. The reason for an application rejection by the Commission shall be recorded in writing and provided to the applicant Within 30 days of the Commission's determination.

9. INTERVENTION, OBJECTION AND HEARING:

a. The Commission shall, within 60 days of official acceptance of the application, schedule a public hearing at which all parties to the case may present testimony and be cross examined concerning the proposed tariff application. The public hearing shall be in accordance with the Commission's Public Hearing Regulation.

b. The Staff of the Commission will be required to provide written testimony, and be available for cross examination at the public hearing explaining its analysis of the application and its recommendations for Commission action. Copies of the written testimony will be made available to registered parties to the case, at least one week before the date of the hearing. Similarly, all other parties in addition to the Staff shall provide copies, to all other registered parties and to the Staff, of any written testimony that they wish to file in the case, at least one week before the hearing.

c. Any person seeking to intervene in a rate proceeding or objecting to the tariff application may present his/her motion to intervene and objection by sending a signed original and four (4) copies to the Secretary of the Commission within fifteen (15) days of publication of notice of acceptance of a tariff application. The motion to intervene and objection must clearly state the name and address of the person seeking intervention and objecting to the application, and the factual grounds for intervention and objection. The objection shall be deemed filed only when it is actually received by the Commission and is accompanied by the required filing fee, which will be fixed by the Commission from time to time. Filing an objection in and of itself does not make a person a party to the proceeding. In order to become a party to a tariff proceeding, a person must file a motion to intervene.

d. The Commission, after review of the motion to intervene, may accept persons as a party to the case. The intervening party's participation in the proceeding will be in accordance with the terms and provisions of the Commission's Hearing Regulation.

e. In the event of the Commission's denial of a motion to intervene, the moving person shall have the right to a motion's hearing, to provide additional bases in support of his motion to intervene in the proceeding. The motion hearing shall be conducted in accordance with the terms and provisions of the Commission's Hearing Regulation.

10. CONTACTS WITH APPLICANT:

Consistent with the Commission's Public Hearing Regulation, from the time the application for consideration of an initial tariff or a change to an existing tariff is officially accepted by the Commission, until the Commission has made a decision in writing and sent it to the Applicant, all contacts with the Applicant shall be in writing through the Secretary of the Commission, or his designated representative. All contact with the Applicant shall relate only to matters of clarification and additional information, to be provided in writing by the Applicant to the Commission. Any other communications will be considered prohibited and grounds for dismissal of the proceeding or rejection of the application.

11. DECISION OF THE COMMISSION:

a. The Commission shall decide an application normally within 90 working days after its official acceptance and issue a written determination or order, signed or initialed by each Member.

b. All Commission determinations and orders are final.

c. Notwithstanding a Commission's final order, a party, within thirty (30) days of the final determination, may submit a petition to the Commission for reconsideration. Such petition and the Commission's actions associated therewith are subject to the provisions of the Commission's Hearing Regulation.

d. Copies of all orders, determinations and decisions made or issued by the Commission, shall be certified under the signature of the Secretary and the seal of the Commission, and shall be made available to any person on payment of such fees as the Commission may, from time to time,

determine. Copies of all such orders, determinations and decisions shall be available on the Commission's website or at the principal office at Dhaka for public inspection free of cost.

12. TERM OF TARIFF:

a. The tariff shall become effective pursuant to the date specified in the order issued by the Commission.

b. The tariff with rates determined by the Commission shall remain in effect until such time as the Licensee shall file for a revision of the tariff, a materially affected party files or the Commission itself initiates a case, suo moto, for revision of the tariff. In the latter case the burden of proof lies with the affected party to show that the current tariff is improper.

c. In no case shall consideration of a new tariff application from the same company be considered within twelve (12) months of the effective date of that initial tariff or rate. The exception would be if an applicant can materially demonstrate that he will endure extreme and undue hardship in the absence of revision. The burden of proof of extreme and undue hardship lies with the applicant, and the Commission will not normally consider such a requirement in variance with the Act.

13. NOTIFICATION TO CUSTOMERS OF INITIAL TARIFF OR CHANGE IN TARIFF:

a. The applicant shall send a BERC approved notice, to each of its customers; indicating either the Commission determined initial tariff; or the Commission approved revised tariff as evidenced by a copy of the original tariff, and the subsequent revised tariff. The notification shall be sent not later than two weeks after the Commission's decision, and not less than seven days prior to the effective date.

b. The applicant shall publish a BERC approved notice in at least two widely circulated national daily newspapers, one in English and one in Bangla, showing therein the original tariff, and the respective changes. This notification shall be published not later than seven days prior to the effective date of the revised tariff.

By the order of the Commission

Dr. Mujibur Rahman Khan

Chairman

Bangladesh Energy Regulatory Commission (BERC)

Anchor Tower , 7 th Level,1/1B, Sonargaon Road

Dhaka-1205, Bangladesh

88-02-9666323

NATURAL GAS DISTRIBUTION

TARIFF METHODOLOGY

1. INTRODUCTION

1.1. The purpose of this natural gas distribution tariff methodology is to establish a standard which will be utilized by a licensee in calculating rates as part of a distribution tariff. By having a regular methodology, a licensee can predetermine the likely outcome of an application for a change in tariffs. Similarly, customers and other interested parties will have confidence in the Commission's examination of the tariffs, that the systems are standardized in a professional manner. Such standardization provides the Commission staff with a reliable basis for examining a tariff application.

1.2. Unique service options will be addressed on a case-by-case basis, if and when the distribution licensee(s) develop a requirement for such services.

1.3. Each distribution licensee shall have published tariff instructions, available to all parties, listing the rates for service, any fixed charges, and appropriate terms and conditions for providing service, termination of service, late payment charges, dispute resolution processes, etc.

1.4. An electric distribution licensee shall have signed wholesale purchase agreements with all natural gas suppliers to its distribution system, and signed transportation agreements with any entity that transports natural gas to the town border stations or city gates of the distribution company. A natural gas distribution licensee shall have service agreements with all of its customers. At the time that agreements are completed, the customers shall be mad aware of the terms and conditions of receiving service, and the current rates.

1.5. Every customer of a distribution licensee shall receive a detailed bill each month. Among other items the bill shall report the gas commodity rate and the distribution rate for service to its customers, and the total of these two services along with other customer charges as applicable.

2. NATURAL COMMODITY RATE

2.1. The natural gas commodity rate is the weighted average of all wholesale natural gas purchases for the preceding quarter as adjusted on a cubic meter basis.

2.2. The distribution licensee does not earn a return or profit on the energy portion of a customer's bill.

2.3. The natural gas commodity rate includes the cost of transportation to the distribution company and the transportation losses.

2.4. This total cost is divided by the amount of natural gas received to produce an energy billing rate for retail consumers. The customer's gas commodity portion of the bill is multiplied times this rate to compute the gas commodity cost for the billing period.

2.6. In the case of the single wholesale supplier, then the energy component is computed as follows:

Gas Commodity Rate = (Wholesale Natural Gas Cost + Transportation Cost + Transportation Loss) / CM Received

Where:

Transportation Loss =

(% Loss * Amount CM Received * Wholesale Natural Gas Cost)/CM Received

2.7. The calculation of the gas commodity rate of the distribution licensee's customer bills are subject to audit by the BERC.

2.8. The gas commodity component of the customer's bill is independent of the rate case used for the purposes of setting the distribution service rate, customer charges, and miscellaneous charges. The gas commodity rate is revised on a quarterly basis, independently of any rate changes made in the service rate and the other charges.

3. NATURAL GAS DISTRIBUTION SERVICE RATE

3.1. Summary

3.1.1. The rate determined by this procedure should provide the least cost to consumers, and provide the opportunity for the licensee to earn sufficient revenues to cover all of its operating expenses, provide for continuing improvement of its operating system, and attract capital for investment.

3.1.2. The rates determined through this procedure are based upon a class cost of service using the cost causative characteristics of each class. The rate schedules for the individual customer classes should be designed to be equitable and reasonable to the customers served. Customers receiving like services should be facing the same charges. Differences in charges should be representative of differences in costs. Absolute equality between costs and revenues may be difficult to achieve in the short run. If there are substantial differences in rates between current rates and those developed pursuant to this methodology, individual customers may view the rates as unreasonable. Continuity is important in the design of rates and movement towards this methodology's standards may have to occur over a period of time. An increase is determined for each class which is adjusted to reflect tax effects. The revenue from customer charges is subtracted from the revenue requirement, if the underlying costs were included in the revenue requirement to establish an increase for the class. The increase is summed with the current class revenues and divided by the test year throughput for each class to determine a class distribution rate.

3.1.3. Among the classes examined in this procedure, the domestic rate will be divided between a fixed domestic rate and a metered rate. The overall domestic class revenue requirement will be borne solely through the domestic fixed and metered rates. No cross subsidy shall be applied wherein revenues from the commercial, industrial, etc. classes are used to support the domestic class.

3.1.4. Pursuant to the BERC Act, the gas service rate and other tariff charges can only be changed once per year.

3.2. Test Year

3.2.1. This is a standardized period, which provides a uniform data base for the calculation of rates. The applicant compiles the company data on the basis of this period. The Commission's analysis and decision is based upon the foundation of data produced from the foundation of data produced for the test year.

3.2.2. The test year is a twelve month period for which complete data is available. Using this twelve month compilation of data, the Commission staff will review the economic analysis that supports the rate and tariff application in order to recommend to the Members of the BERC whether the filing is reasonable. The Commission hereby defines the test year, for the distribution tariff rate applications placed before it, as the most recent fiscal year ending on 30 June. In the case of a distribution applicant with no operating history, then the Commission will consider the best estimate for a fiscal year.

3.2.3. Every two years, each distribution licensee shall perform a consumption study of its domestic class customers on the fixed schedules. A statistically random sample of individual customers, or a sample where customers of the same schedule can be grouped, will have their consumption metered for a period during each quarter. The period and sample shall be determined through a statistical analysis to achieve a 97% statistical degree of confidence for each of the fixed domestic rates.

3.3. Cost of Service

3.3.1. The cost of service develops the individual class of service rates (domestic, domestic rated commercial, commercial, industrial, compressed natural gas fuel stations, seasonal, captive power, small power, independent power producers, public power generators, firm and interruptible transportation, etc.) on a cost causative basis.

3.3.2. The class specifications, discussed in this methodology, are not binding upon the distribution licensees. Distribution licensees should propose as part of their rate applications, the customer class configurations and specifications that most appropriately reflect the licensee's distribution requirements. The allocation approaches remain the same regardless of the class number and type.

3.3.3. The summation of class revenue requirements equals the overall revenue requirement for the gas distribution licensee.

3.3.4. The costs, return, and revenues are directly assigned or are allocated to the respective distribution customer classes in order to develop rates for the individual classes.

3.3.5. Expenses, incomes, and rates would be based on the embedded costs developed for that test year.

3.3.6. All expenses and other financial factors cannot be directly assigned to individual customers classes such as residential or industrial. For that reason, some costs must be allocated on the basis of factors to the respective classes. These may be based on demand, commodity, customer, and revenue allocation factors. A section later in this methodology will discuss specific factors used in allocation.

3.4. Revenue Requirement

3.4.1. Summary

3.4.1.1. The overall revenue requirement is the amount of income that the distribution licensee should have the opportunity to earn in order to maintain operations and attract capital for investment, but still maintain the least cost for consumers.

3.4.1.2. The total overall annual revenue requirement is the sum of a return on rate base, plus the sum of the total annualized costs of operating the distribution utility.

Total Annual Revenue Requirement = Return on Rate Base + Total Costs

3.4.1.3. A revenue requirement is developed for each class of service. The sum of the individual revenue requirements must equal the licensee's overall revenue requirement.

The annual revenue requirement for each class is determined on the basis of test year data. It is compared to the record of current revenues from each class and an increase is computed for each class. The revenue increase is the amount of additional revenue needed by the utility to achieve the class revenue requirement. Since the revenue increase will also be taxed, to insure that the utility has the opportunity to receive the net income necessary to achieve the revenue requirement, the increase is augmented to recover the tax effect. Once the revenue increase is determined, it is summed with the amount of current revenues for each to achieve the test year total revenue requirement. This is divided by the class distribution throughput of the test year to develop the class distribution rate.

3.4.2. Rate Base or Qualifying Assets

3.4.2.1 . Summary

3.4.2.1.1. The rate base for a distribution licensee shall consist of the depreciated used and useful assets; plus the regulatory working capital.

Rate Base = Depreciated Used & Useful Assets + Regulatory Working Capital

3.4.2.1.2. The total rate base is the sum of the directly assigned and allocated rate base of the individual customer classes.

3.4.2.2. Used and Useful Assets

3.4.2.2.1. The physical asset accounts considered for a gas distribution utility are broken into three categories – intangible plant, distribution plant, and general plant.

Reference for appropriate plant account numbers, definitions, etc. should be made to the BERC uniform system of accounts, when it becomes available.

3.4.2.2.1.1. Intangible plant would consist of organization, franchises and consents, and miscellaneous intangible plant. Allocate intangible plant costs based on a demand allocation.

3.4.2.2.1.2. Natural gas distribution plant would include land and land rights; structures and improvements; mains; compressor station equipment; measuring and regulating station equipment – general; measuring and regulating station equipment -- city gate check stations; services; meters; meter installations; house regulators; house regulatory installations; industrial measuring and regulating station equipment; other property on customers' premises; and other equipment.

3.4.2.2.1.3. As noted in the table above, various assets are allocated to the customer classes on the basis of demand. Referring to the later discussion in this methodology on the demand allocator, the total book value for these plant items will be multiplied by each classes demand allocator and entered into a summary table.

3.4.2.2.1.4. Services, meters, installations on customer premises, house regulators, industrial metering, other property and other equipment are allocated to the respective rate classes based upon direct assignment to the customer classes, for example, the cost of domestic meters is listed in the summary table under domestic customers. Any other costs, which cannot be directly assigned, will be multiplied by the customer allocation factors listed later in this methodology and entered into the summary table.

3.4..2.2.1.5. New assets shall be included in the asset valuation for establishing rates, when they become used and useful, and the value shall be at the original acquisition cost.

3.4.2.2.1.6. General plant would include land and land rights; structures and improvements; office furniture and equipment; transportation equipment; stores equipment; tools, shop and garage equipment; laboratory equipment; power operated equipment; communication equipment; and miscellaneous equipment. Allocate general plant based on demand and energy related costs.

3.4.2.2.2. New assets shall be included in the asset valuation for establishing rates, when they become used and useful, and the value shall be at the original cost.

3.4.2.2.3. Depreciation is a process which distributes the original cost of depreciable assets, adjusted for net salvage value, over the normal useful life of the property in a systematic and rational manner.

3.4.2.2.3.1. Additions and improvements are charged to the respective distribution plant accounts at original acquisition cost. Upon the normal retirement of a distribution plant asset, its original cost is charged against the accumulated depreciation reserve together with the cost of removal, less salvage value. The cost of maintenance, repairs, and the replacement of minor items is charged to operating expenses as incurred.

3.4.2.2.3.2. For purposes of public utility accounting for rate making purposes, the BERC requires that a straight-line depreciation method will be applied for all public utility assets. The useful or standard life of an asset shall be specified in accordance with the International Accounting Standards and such depreciation life schedules as established by the BERC. For purposes of this regulation, straight line depreciation rates are considered acceptable over the following life of equipment and plant:

3.4.2.2.3.3. The amount of the current depreciation will be added as an expense in total costs at the current book value of the assets, and is not subject to re-evaluation based upon any subsequent revision of the asset valuation.

3.4.2.2.3.4. In making application for a rate or tariff change, the natural gas distribution utility must file a schedule which shows the original acquisition cost of the asset, the accumulated depreciation, the net asset value after reduction for depreciation, and the amount of depreciation to be included in the rate application for the test year.

3.4.2.2.3.5. The allocation of depreciation costs shall be allocated to the customer classes in the same manner as the plant costs themselves are allocated.

3.4.2.3. Regulatory Working Capital

3.4.3.2.3.1. Summary

3.4.2.3.1.1. The last major element of rate base is regulatory working capital. In distribution licensee tariff rate design, “regulatory working capital” has a different meaning than the term “working capital” in normal accounting. Regulatory working capital is a measure of licensee funding of daily operating expenditures and a variety of non-plant investments that are necessary to sustain the ongoing operations of the licensee. Fundamentally, it is the normal operating funds of a licensee which carry it forward from month to month.

3.4.2.3.1.2. It is the sum of the cash working capital, materials and supplies inventory, and any prepayments made.

Distribution Regulatory Working Capital = Cash Working Capital + Materials and Supplies Inventory + Prepayments

3.4.2.3.2. Cash working capital

3.4.2.3.2.1. Cash working capital represents the licensee provided cash required for payment of operation expenses, to maintain compensating cash balances, and similar needs, between the time the expenditures are necessary to provide the services and the time collections are received for the services.

3.4.2.3.2.2. For a licensee, the formula calculates 1/6th (approximately 60 days) of operation and maintenance expenses for one year. For a well managed natural monopoly, this computation represents the average time and amount that the licensee must provide cash for operations before collections are received from the service.

Cash Working Capital = 1/6 x (Annual Operation & Maintenance Expenses)

3.4.2.3.3. Materials and supplies inventory

2.3.2.3.3.1. Materials and supplies are the licensee's inventory value for material and supplies necessary to meet daily requirements of providing service.

2.3.2.3.3.2. A 12-month average for the test year is used.

Materials and Supplies Inventory = (Total of 12 Months Value Materials and Supplies) / 12

3.4.2.3.4. Prepayments

3.4.2.3.4.1. Prepayments are made in advance of the period to which they apply and include items such as prepaid rents, insurance, and taxes. The amounts normally allowed are based on the same standards outlined above for M&S inventories.

3.4.2.3.4.2. The average monthly measurement period should encompass more than a single test year review, since certain pre-paid expenses (such as prepaid insurance) often are made for periods in excess of one year. Sum the prepaid balances over whatever the longest cycle of any individual component of the prepayment item, and then average it for the test year period. For example, if during the test year, insurance was prepaid for three years, then divide the total by three, and for Tariff Rate purposes enter this amount for the annual prepayment amount. Divide this by twelve months to develop a monthly average value for prepayments to be included in working capital.

3.4.2.3.4.3. Advanced income tax is a prepayment included in regulatory working capital. Advanced Income Tax is charged at the rate of 2.5% of the invoice value of the imported item, and also paid each quarter to the Government on the basis of regularly adjusted quarterly estimates. For regulatory working capital purposes, the licensee can receive a return on a portion of the advance income tax paid. The licensee shall divide advance income tax paid during the test year by 12 months to develop an amount that is included in regulatory working capital.

3.4.2.3.4.4. Customer deposits are normally required for a distribution licensee to provide service. These represent insurance for the licensee against the customer defaulting on payment. Distribution licensees utilize these deposits in daily meeting of working capital requirements. Thus for purposes of calculating return on working capital, since these funds are not funds provided by the licensee, these should be subtracted from the working capital total. If the distribution licensee pays interest on the funds deposited, these interest costs are treated as an expense.

3.4.2.3.4.5. Working capital is allocated to the respective distribution classes on the same percentage basis as the total allocation of assets. For example, if 80% of the total assets are allocated to the domestic class, then 80% of the working capital requirement should be allocated to the domestic class.

3.4.3. Rate of Return on Assets

3.4.3.1. Summary

3.4.3.1.1. The distribution rate of return on qualifying assets shall be calculated as the weighted average cost of capital in accordance with the following formula:

Average Cost of Capital = [(Equity Capital x E%) + (Debt Capital x D%)]

[(Equity Capital + Debt Capital)]

where:

“E%” is a rate of return on the equity capital of the company, which is computed as described in the following section.

“D%” is a calculated weighted value of interest rate for debt capital, which is computed as described in the section following the discussion on return on equity.

3.4.3.1.2. The overall rate of return calculated for the licensee is applied uniformly over all distribution classes.

3.4.3.2. Return on Equity

3.4.3.2.1. The rate of return on the equity capital shall be calculated as the weighted average of equity in accordance with the following formula:

E% = [(Common Stock Amount x Dividend Rate) + (Remaining Equity Amount x Non-Stock Rate)]

[(Common Stock Amount + Remaining Equity Amount)]

3.4.3.2.2. In the case of common stock, the amount of common stock outstanding during the test year is multiplied by the last dividend rate paid during the test year.

3.4.3.2.3. In terms of the remaining equity existing within the Distribution licensee, if government owned, then the government's borrowing rate is utilized.

3.4.3.2.4. In the case of licensees, which are wholly or partially owned by the government, the cost of capital for remaining equity would equal the government's cost of capital. For purposes of rate development, the most recent treasury bill auction rate, pursuant to central bank auction, for the two-year Bangladesh treasury bills shall be utilized.

3.4.3.2.5. If the licensee is a privately held distribution company that falls under the regulation of the BERC, then the remaining equity rate can be computed on the basis of the following discussions.

3.4.3.2.6. The Commission's preference in determining the return on equity is a form of a capital asset pricing model (CAPM.). It assumes that the cost of equity is the sum of a risk-free rate of return, plus a return to compensate investors for market risk.

3.4.3.2.7. It is the responsibility of the licensee applying for a tariff rate change to recommend a rate of return on equity, and provide adequate support to justify that equity rate. The Commission upon review will determine that equity rate pursuant to a Commission staff analysis and the review of all evidence in the public hearing.

3.4.3.2.8. Other methods for determining a return on equity are the discounted cash flow, risk premium approach, and comparable earnings approach.

3.4.3.2.8.1. The discounted cash flow assumes that the price of a stock is the present value of the income to be received from it in the future. The difficulty in utilizing this method is trying to assign a value to investor expectations. If the licensee stock is not publicly traded, or newly traded, it becomes a very subjective decision.

3.4.3.2.8.2. The risk premium method is also common. It assumes that equity has a required rate of return higher than debt. The cost of equity is the long-term cost of debt, plus a risk premium. The determination of the risk premium is again based upon historical stock records.

3.4.3.2.8.3. The comparable earnings approach takes a sample group of other licensees and develops a composite rate of equity return to be proposed for the licensee. Again records of similar equity rate proceedings and the results are required.

3.4.3.2.9. The Commission will consider tariff applications with all of these approaches, but prefers a method similar to the Capital Asset Pricing Model (CAPM), with a risk free rate of return plus an additional factor for market risk. The burden of proof with regard to establishing the rate of return remains with the licensee.

3.4.3.2 .10. It is the responsibility of the distribution licensee applying for a rate change to recommend a rate of return on the non-stock equity, and provide adequate support to justify that rate. The Commission upon review will determine that rate pursuant to Commission staff analysis and the review of all evidence in the public hearing. Absent a qualified and approved recommendation by the distribution utility, for a partially government-owned licensee, the Commission will only accept the most recent treasury bill auction rate for two year notes that has occurred during the fiscal test year.

3.4.3.3. Return on Debt

3.4.3.3.1. The rate of return on the weighted value of interest rate for debt capital shall be calculated in accordance with the following formula:

D%= [(Long Term Debt x Debt Rate) + (Preferred Stock Amount x Dividend Rate)]

[(Long Term Debt + Preferred Stock Amount)]

3.4.3.3.2. If there are multiple long term debt instruments at different interest rates, or multiple issuance of preferred stock at different dividend rates exist, then a similar weighted cost calculation would be performed for each category.

3.4.3.3.3. In terms of long term debt rate, the utilities that are wholly owned government entities shall use the loan rate applied by the government of Bangladesh , even if the loan funds derive from donor loans at a lower rate.

3.4.3.3. 4. The loan amounts used in this calculation should represent the outstanding balance (or unpaid balance) of the loan – not the original loan amount.

3.4.3.3. 5. The applicant utility must provide a long term debt summary, which indicate the original amount of the long term debt by source, amount, and date; the accumulated principal reduction; the time period during the test year wherein the loan was applicable; the interest rate; the amount of interest paid during the test year; the amount of principal paid during the test year; and the amount of interest paid during the preceding fiscal year.

3.4.3.4 . Overall Rate of Return

3.4.3.4.1. The fundamental formula for computing the rate of return, as shown in the generic section of this regulation, would be applicable for an independently owned or a government owned Distribution company:

AC = [(Equity Capital x E%) + (Debt Capital x D%)]

[(Equity Capital + Debt Capital)]

3.4.3.4.2. This rate of return should provide the distribution utility with the opportunity to earn a return on the investment in the company which is reasonable based upon its obligations for long term debts and its ability to raise capital.

3.4.4. Total Costs

3.4.4.1. General Discussion

3.4.4.1.1. Total Costs are the sum of costs associated with the operation and maintenance (O&M) of the licensee's system, the straight-line depreciation costs of used and useful assets used for distribution for the year, taxes, and any other necessary costs related to the operation of the licensee's system.

Total Costs = O&M Costs + Depreciation + Income & Other Taxes

3.4.4.1.2. Costs should be formulated in accordance with Bangladesh Accounting Standard and the Uniform System of Accounts, when published by the Commission.

3.4.4.1.3. Calculations of costs for each tariff application shall be based on the analysis of twelve months of actual data. Where possible costs can be assigned directly to distribution classes, they should be, otherwise costs are allocated.

3.4.4.1.4. For the purpose of tariff calculation, all costs shall be detailed as much as possible in order to allow proper controls by the Commission.

3.4.4.1.5. O & M costs are the expenses incurred in a business arising from or directly related to producing the service as well as the costs of maintaining the system in service.

3.4.4.1.6. The amount of the current depreciation will be added as an expense in total costs at the current book value of the assets, and is not subject to re-evaluation based upon any subsequent revision of the asset valuation.

3.4.4.1.7. The taxes included as part of the cost of service include all applicable taxes. They are added as an expense.

3.4.4.1.8. These costs are allocated to individual customer classes as discussed below.

3.4.4.2. Operation and Maintenance Expenses

3.4.4.2.1. Operation and Maintenance (O & M) costs are the expenses incurred in a business arising from or directly related to producing the service as well as the costs of maintaining the system in service.

3.4.4.2.2. O&M expenses for distribution utilities are broken into the major categories of distribution, customer accounts, sales, and administrative and general expense.

3.4.4.2.2.1. Distribution Expenses

3.4.3.2.2.1. Distribution expenses are broken into two major categories – operations and maintenance.

3.4.3.2.2.2. In terms of operations expenses, costs are broken into: distribution load dispatching; compressor station labor and expenses; compressor station fuel and power; mains and services expenses; measuring and regulating station expenses – General; measuring and regulating station expenses – Industrial; measuring and regulating station expenses -- city gate check stations; meter and house regulator expenses; customer installations expenses; other expenses; and rents.

3.4.3.2.2.3. Maintenance expenses include: maintenance supervision and engineering; maintenance of structures and improvements; maintenance of mains; maintenance of compressor station equipment; maintenance of measuring and regulating station equipment – general; maintenance of measuring and regulating station equipment – industrial; maintenance of measuring and regulating station equipment -- city gate check stations; maintenance of services; maintenance of meters and house regulators; and maintenance of other equipment.

3.4.4.2.2.2. Customer Accounts Expenses

3.4.4.2.2.2.1. Customer Accounts Expenses are considered operations expenses only. They include supervision; meter reading expenses; customer records and collection expenses; uncollectible accounts; and miscellaneous customer accounts expenses.

3.4.4.2.2.2.2. These costs are allocated to the respective customer classes on the basis of the customer allocation ratios.

3.4 .4.2.2.3. Sales Expenses

3.4.4.2.2.3.1. Sales Expenses are considered operations expenses only. They include supervision; demonstrating and selling expenses; advertising expenses; and miscellaneous sales expenses.

3.4.4.2.2.3.2. These costs are allocated to the respective customer classes on the basis of the customer allocation ratios.

3.4 .4.2.2.4. Administrative and General Expenses

3.4.4.2.2.4.1. Administrative and General Expenses are broken into operation and maintenance expenses, with the bulk of the expenses being operation based. Operation expenses include administrative and general salaries; office supplies and expenses; administrative expenses transferred – credit; outside services employed; property insurance; injuries and damages; employee pensions and benefits; franchise requirements; BERC license fees; duplicate charges – credit; general advertising expenses; miscellaneous general expenses; and rents

3.4.4.2.2.4.2. Maintenance expenses include only maintenance of general plant.

3.4.4.3.2.2.4.3. These costs are allocated to the respective customer classes on the basis of the customer allocation ratios.

3.4.4.2.2.5. Foreign Currency Exchange Fluctuation

3.4.4.2.2.5.1. Given that Bangladesh utilities have dollar denominated, or other international currency denominated, loans from international banking institutions such as the Asian Development Bank, a utility incurs revenue loss as a result of the devaluation of the Taka in comparison to the U.S. dollar or another international denominated currency, to the extent that revenues used to repay the loans are obtained from the local economy. Although debt related, this amount should be treated as an expense, which should be computed based upon the current exchange rate at the end of the fiscal year minus the exchange rate at the beginning of the fiscal year multiplied times the dollar amount, or other international currency, of loan repaid during the fiscal year. This will be included as an administrative and general expense.

3.4.4.2.2.5.2. The exchange rate difference of materials and equipment which has already entered the distribution company's possession cannot be reassessed and an exchange rate fluctuation calculated for that material or equipment already in the distribution company's possession can not be considered for rate development purposes.

3.4.4.2.2.5.3. The allocation of currency fluctuation expenses should be performed on the basis of demand allocation.

3.4.4.2.2.5.4. Where items listed in the table above have joint allocations such as demand and commodity, see the following discussion on how to compute..

3.4.4.2.2.5.5. Expenses used in the calculation of a monthly customer charge or other miscellaneous charge should not be included in the class total operation and maintenance expenses.

3.4.4.3. Depreciation

3.4.4.3.1. The amount of depreciation included as a cost is the total annual depreciation for all used and useful assets for the test year.

3.4.4.3.2. It is allocated to the respective customer classes on the percentage basis of the individual plant accounts.

3.4.4.4. Income and Other Taxes

3.4.4.4.1. A licensee's taxes are an expense that should be recoverable as a business cost in providing regulated service.

3.4.4.4.2. Three taxes could directly affect a Distribution licensee's operations in Bangladesh – value added tax (VAT), land tax, and income tax.

3.4.4.4.2.1. To the extent that licensee makes payroll or invoice deductions from employee or contractor payments, for payment to the government, these are not included in the licensee's cost of service for tariff rate design purposes. To the extent that the licensee provides matching payments to these deductions above the amount collected, then these are booked as an expense as part of the cost of service. If the licensee makes any other tax payments not already discussed in this methodology that has a direct result on the distribution of natural gas, then these are booked as an expense as part of the cost of service.

3.4.4.4.2.2. Value Added Tax (VAT) is collected at the distribution level.

3.4.4.4.2.3. Land tax is not directly affected by the amount of distribution and generally is booked as a miscellaneous cost.

3.4.4.4.2.4. Income tax is charged as follows: (1) for a company which is not publicly traded, the rate is 40%; and (2) a publicly traded company has a rate of 30%. The distribution licensee, for income tax purposes will fall under either category (1) or (2), and must support in the rate case filing, the rate being applied by the tax department.

3.4.4.4.3. At the time of importing materials to Bangladesh , the licensee pays a VAT, a Customs Duty, and Advanced Income Tax. Advanced Income Tax is charged at the rate of 2.5% of the invoice value of the imported item.

3.4.4.4.3.1. For imported materials, the VAT and Customs Duty charged are a part of the acquisition cost of the asset or material, and should be included when booking the asset or material as part of its acquisition value. That amount will be used for purposes of depreciation and for computing a return on assets.

3.4.4.4.3.2. If the licensee pays VAT on any item it purchases, it is included in the book cost of that asset or item as part of the acquisition cost of the item for Tariff Rate design purposes.

3.4.4.4.4. In addition to the advance income tax collected on import of materials, the licensee will pay estimated advance income tax to the Government on a quarterly basis. The licensee will make an estimate of taxes for the fiscal year. The licensee has an obligation to pay, in advance payments, at least 75% of the estimated taxes. Each quarter, the licensee then adjusts the estimate for the new quarter based upon actual revenues and tax liability for the past quarter. At the end of the fiscal year, the income tax payable is netted against the advanced income tax, paid via quarterly payments as well as per the advance income tax collected upon import of materials, and the net payable income tax is submitted to the government. If the accumulated advance income tax exceeds the amount of income tax owed to the government for that fiscal year, then no additional income tax is paid, and any surplus advance income tax is carried forward on the books into the next fiscal period.

Advanced income tax is a prepayment and a portion should be included in regulatory working capital, as described in the working capital section.

3.4.4.4.5. The amount of income tax to be included as a cost expense for tariff rate design during the test year is the actual amount of income tax paid to the Bangladesh government as booked for the test year.

Therefore, the taxes included for tariff rate design purposes within a test year are:

Taxes = Land Tax + Income Taxes Paid

3.4.4.4.5. Taxes are allocated to the respective classes on the basis of revenues. If the domestic class produces 70% of the revenues, then 70% of the taxes should be allocated to the domestic class.

3.4.5. Allocation Factors

3.4.5.1. For allocation purposes the licensee will compile the following: distribution throughput for the respective classes; the number of customers in the classes, the peak day requirements, the individual class peaks of the groups, the gross plant, and the amount of taka paid for labor.

3.4.5.2. Commodity/Capacity Allocator

Some of the costs and asset values are allocated on the basis of commodity and capacity. Commodity represents the average use of the system and capacity represents the peak day requirements placed on the system.

3.4.5.2.1. The average daily requirement is computed by taking the annual throughput in MCM and dividing by 365. This represents the commodity needs of the system.

3.4.5.2.2. Based upon measured transmission volume for the system's peak day, the amount above the average daily transmission volume is determined. This amount represents the capacity needs of the system.

3.4.5.2.3. The commodity needs are then divided by the peak day throughput and this becomes the commodity allocator. The capacity needs are divided by the peak day throughput and this becomes the capacity allocator.

3.4.5.3. Throughput Allocator

The throughput allocator consists of the total amount of natural gas transported, based upon accounting records, for those customers receiving the various classes of service. Each amount is represented as a decimal fraction of the total throughput.

3.4.5.4. Number of Customers Allocator

The number of customer allocator, based upon accounting records, is the number of customers who received distribution service during the test year for each of the categories of service. The number is divided by the total number of customers to establish a percentage.

3.4.5.5. Peak Day Requirements Allocator

The peak day allocator is the amount of natural gas transported by each class on the system peak day during the test year. The class is represented as a percentage of the total peak day throughput.

3.4.5.6. Revenue Allocator

The revenue allocator is the percentage of total revenue by class received by the licensee during the test year.

3.4.5.7. Labor Allocator

The labor allocator is the percentage of total labor expense each class causes the licensee to incur based upon time sheet records for the test year.

3.4.5.8. Average and Excess Demand Allocator

peak day – for example, seasonal rates. The calculation of the allocator is best demonstrated by the following table

Based upon billing records, the test year annual volumes are listed in column 1 for the respective classes, as well as the total annual throughput. The system peak-day throughput is listed in total only in column 2. Based upon billing records for the test year, the maximum throughput for each class is listed in column 3, and then added together to achieve a total. The class maximum throughput may occur anytime during the test year. It may occur at another day than the overall system peak day depending upon the characteristics of the class.

The amounts listed in column 1 are divided by 365 to produce an average daily throughput or demand on the system. In affect, this is the “used” portion of the transmission system or the minimum capacity needed to deliver the total gas transported. The difference between the average total and the system peak total is the “unused” portion of the capacity – the amount that only exists to support peak requirements. In the above example 4100 MMCM of Power Class throughput divided by 365 produces an average daily firm throughput of 11.23 MMCM per day.

The process demand or throughput is computed by subtracting the average demand (column 4) from the class maximum demand (column 3). In the above example, the 33.70 MMCM per day at class maximum throughput for power has 11.23 MMCM subtracted to produce a process demand of 22.47 MMCM.

The excess capacity required to meet peak day requirements is then assigned to the respective classes in relation to this process demand, by first subtracting the total average demand of 20.78 MMCM from the peak day throughput of 46.81 MMCM per day, to yield 26.03. The process demand or throughput, for example, for power (22.47 MMCM) is then divided by the total process demand (38.15), and that decimal value is multiplied times the 26.03, to yield 15.33 MMCM per day of excess demand assigned to power distribution. Thus the excess capacity above average use for which the firm class is responsible is represented by this number.

The average and excess demand is then the sum of the amounts in column 4 (average) plus the amounts listed column 6 (excess). For example, for the power class of service, 11.23 plus 15.33 equals 26.56 - this is as shown in column 8, as 57% of the total peak day capacity requirement of 46.81 MMCM per day. Thus any capacity costs, which cannot be directly assigned, would be allocated to the cost computation in developing power class rates by multiplying by 0..57. This process can be used for any number of classes.

3.4.6. Recommended Operating Revenues

3.4.6.1. The recommended operating revenues for each distribution class would be the sum of the proposed return on rate base plus the total operating expenses which include the current year depreciation, and taxes.

3.4.6.2. This calculation is performed for each customer class and the sum of the customer class recommended operating revenue must equal the overall revenue requirement. Minor mathematical difference may arise, and any differences should be distributed among the customer classes in proportion to the already calculated class operating revenue.

Recommended Operating Revenue = Proposed Return on Rate Base + Operating Expenses

3.4.6.3. This amount is compared to the current operating revenues to determine the amount of the increase required that the licensee will have the opportunity to earn to achieve the revenue requirement.

3.4.7. Total Current Operating Revenues

3.4.7.1. The total current operating revenues for each class would be the sum of distribution service revenues, income from other services rendered, any interest income, and any miscellaneous income.

Total Current Operating Revenues = Distribution + Other Service + Interest + Miscellaneous

3.4.7.2. Miscellaneous income would include revenue from customer charges, reconnection charges, etc.

3.4.7.3. Current revenues for individual distribution classes a developed based upon actual book revenues.

3.4.8. Proposed Revenue Increase

3.4.8.1. The proposed revenue increase is the difference by class between the current revenues and the recommended operating revenues. This difference is the amount of revenue that rates would need to be increased to provide the licensee with the opportunity to achieve the recommended rate of return and receive sufficient funds to cover operating expenses.

Proposed Revenue Increase = Recommended Operating Revenues - Current Revenues

3.4.8.2. These proposed class revenue increases are subject to income tax. If these proposed increases are directly added to current revenues, then the licensee after implementing the increase would not receive the recommended operating revenues. Future revenues would be reduced by the amount of the increased taxes. To insure the licensee has the opportunity to earn the revenues recommended, the amount of the increase is “grossed up”. Essentially, the increase is enlarged to allow for the increased taxation. A revenue conversion factor is developed which is multiplied times the revenue increase.

3.4.8.2.1. The saem revenue conversion factor is used for all classes. The revenue conversion factor is calculated by computing a formula. The formula is the number “1” divided by the number “1 minus the effective income tax rate”.

Revenue Conversion Factor = 1/(1- Income Tax Rate)

3.4.8.2.2. Once the conversion factor has been developed, the amount of the increase is multiplied times the proposed revenue increase to develop a recommended revenue increase.

Recommended Revenue Increase = Proposed Revenue Increase * Revenue Conversion Factor

3.4.9. Total Recommended Revenue Requirement

The total recommended revenue requirement is the sum of the current class revenues plus the recommended class revenue increase.

Recommended Revenue Requirement = Total Current Revenues + Recommended Revenue

Increase

3.5. Distribution Rate

3.5.1. The distribution rate for each class is simply computed by dividing the recommended revenue requirement by the annual distribution throughput in MCM for each class.

Distribution Rate = Recommended Revenue Requirement/Annual Distribution Throughput

3.5.2. As distribution services evolve in Bangladesh establishing such services as firm and interruptible services, etc, the BERC will address these changes on a case by case basis and amend this methodology as needed.

4. Miscellaneous Charges

4.1. Summary

4.1.1. The natural gas distribution licensees may have need of establishing a number of miscellaneous charges to satisfy particular requirements needed to serve a customer class. This could include reconnection charges, late payment charges, specialized meter or distribution charges, etc.

4.1.2. The individual distribution licensee in making a rate application should indicate the miscellaneous charges it proposes to levy on its customers, and provide complete working papers which justify the costs utilized to compute the charge. Any plant or any expense used to calculate such a rate does not get included again in the calculation of the distribution rate for natural gas. The revenues received from miscellaneous charges will be included in satisfying the overall revenue requirement..

4.2. Customer Charge

4.2.1. A significant miscellaneous charge is the customer charge. Costs occur as a result of customers being connected to the licensee's system, regardless of usage. Such costs should be represented in the design or structure of rates. The BERC's methodology herein describes a calculation for the establishment of a domestic customer flat charge.

4.2.1.1 Domestic Flat Customer Charge

4.2.1.1.1. The BERC calculation procedure for the establishment of the domestic flat customer charge would be as follow