Electricity Tariffs for the Period 2011-2015 in Sri Lanka

Consultation Paper on Setting Tariffs for the period 2011-2015 1

Consultation Paper on Setting Tariffs for the

Period 2011-2015

Public Utilities Commission of Sri Lanka


Consultation Paper on Setting Tariffs for the Period 2011-2015

TABLE OF CONTENTS

1. PREAMBLE ............................................................................................................................................................... 5

2. INVITATION FOR PUBLIC COMMENTS ......................................................................................................... 6

3. ALLOWED REVENUES FOR LICENSEES ........................................................................................................ 7

3.1 SALES FORECAST AND ALLOWED LOSSES .......................................................................................................... 7 3.1.1 Sales Forecast and Losses filed by Licensees ........................................................................................... 7 3.1.2 Adjusted Sales Forecast and Allowed Losses ........................................................................................... 7

3.2 ALLOWED COSTS OF LICENSEES ...................................................................................................................... 10 3.2.1 Debt Restructuring of CEB Licensees ..................................................................................................... 10 3.2.2 Costs of Distribution Licensees ............................................................................................................... 10 3.2.3 Costs of the Transmission Licensee ......................................................................................................... 14 3.2.4 Revenue Requirements of the Single Buyer ............................................................................................. 15 3.2.5 Non-dispatchable Renewable Energy Power Plants .............................................................................. 17 3.2.6 Allowed Revenues of the Single Buyer .................................................................................................... 18 3.2.7 Provision for the Settlement of Short-term Debts ................................................................................... 18

3.3 ANALYSIS OF COSTS OF LICENSEES ................................................................................................................. 19

4. GOVERNMENT SUBSIDIES ................................................................................................................................ 20

4.1 LONG-TERM DEBTS WRITTEN-OFF AND RESCHEDULED ................................................................................... 20 4.2 CONCESSIONS ON FUEL PRICES ........................................................................................................................ 21 4.3 PROCEDURE IF SUBSIDIES OR CONCESSIONS ARE CHANGED ........................................................................... 21

5. ROAD MAP FOR TARIFF REBALANCING .................................................................................................... 22

5.1 INTRODUCTION ................................................................................................................................................ 22 5.2 THE ROAD MAP FOR TARIFF REFORMS ............................................................................................................. 22 5.3 TIME INTERVALS PROPOSED FOR TOU TARIFFS .............................................................................................. 23

6. PROPOSED TARIFFS ........................................................................................................................................... 24

6.1 LEVY ON STREET LIGHTING ............................................................................................................................. 24 6.2 PROPOSED TARIFFS FOR 2011 .......................................................................................................................... 25 6.3 FORM OF THE MONTHLY STATEMENT OF ACCOUNT ......................................................................................... 26

7. CONCLUSION ........................................................................................................................................................ 27


LIST OF TALBLES

Table 1- Sales Forecasts and Loss Allowances Filed by Distribution Licensees ................................. 7

Table 2- Sales Forecast and Loss Allowances Filed by the Transmission Licensee ............................ 7

Table 3- Allowed Sales, Purchases and Losses ............................................................................ 8

Table 4- Distribution and Retail Revenues Filed and Allowed Revenues ......................................... 12

Table 5- Transmission and BSOB Revenues Filed and Allowed Revenues ....................................... 15

Table 6- Filed and Allowed Payments to Non-dispatchable NCRE Power Plants ............................... 17

Table 7- Allowed Revenue of the Single Buyer (incl Transmission and BSOB) ................................. 18

Table 8-Filed Provisions to Settle Short-term Debts of CEB Licensees ........................................... 18

Table 9- Analysis of Allowed Costs of Transmission and Distribution Services ................................ 19

Table 10- Composition of the Costs to end-users (January - June 2011) ....................................... 20

Table 11- Analysis of the Cost Break-up of end-users ................................................................. 20

Table 12- Evaluation of the Government Subsidy owing to Long-term Debt Relief .......................... 20

Table 13- Composition of Costs including Government Subsidies .................................................. 21

Table 14- Costs of Supply and Subsidies Required in Year 2011 if Present Tariffs Continue .............. 22

Table 15- Approved Roadmap for Tariff Rebalancing ................................................................... 22

Table 16- Proposed Intervals in the TOU Tariff ........................................................................... 23

Table 17- Allowed Energy Sold to Approved Street Lighting to be Recovered through the Levy for year 2011 .................................................................................................................................... 24

Table 18- Existing Tariffs and Proposed Tariffs for January-June 2011 .......................................... 25

Table 19- Proposed Form of the Monthly Statement of Account (LV Customers) ............................. 26

Table 20- Proposed Form of the Monthly Statement of Account (LV bulk and MV customers) ........... 27


List of Abbreviations

BSOB Bulk Supply and Operations Business

BST Bulk Supply Tariff

CAPEX Capital Expenditure

CEB Ceylon Electricity Board

DL Distribution Licensee

DL1 Distribution and Supply Licensee for CEB Distribution

Region 1


Region 2


Region 3


Region 5

DL5 Distribution and Supply Licensee LECO

FSA Fuel Supply Agreement

CEB GL CEB Generation Licensee

GWh Giagawatt hour

kVA kilovolt ampere

kW kilowatt

kWh kilowatt hour

LECO Lanka Electricity Company (Pvt) Ltd.

LKR Sri Lanka Rupee

LV Low Voltage

MV Medium Voltage

MWh Megawatt hour

NCRE Non-Conventional Renewable Energy

O & M Operations & Maintenance

OPEX Operating Expenditure

PPA Power Purchase Agreement

SPPs Small Power Producers

TL Transmission and BSOB Licensee

TOU Time of Use

VAT Value Added Tax

WIP Work-in-Progress


Consultation Paper on Setting Tariffs for the Period 2011-2015

1. PREAMBLE This consultation paper is issued under Section 30 of the Sri Lanka Electricity Act No 20 of 2009 (the “Act”), for the purpose of allowing consumers and other interested parties to participate in setting the tariffs in accordance with the cost-reflective methodology approved by the Commission. In accordance with Section 32(2)(a) of the Act, the Commission, on 26th July 2010, approved a cost-reflective Methodology for Tariffs and subsequently issued the same to the Transmission Licensee and all the Distribution Licensees . The Methodology for Tariffs issued to the Licensees is available as a separate document1. The methodology has the following key features: (i) The purchase of generation by the Transmission and Bulk Supply Licensee (the “Single

Buyer”) will be passed-through to the Distribution and Supply Licensees, and thereby to the end-use customers. The revision period for such approved generation pass-through costs will be once in six months.

(ii) Tariffs chargeable by the Transmission and Bulk Supply Operations Business of the Transmission Licensee will be based on multi-year tariff principles, where the Base Allowed Revenue for the Transmission Licensee will be capped at the same price each year for the entire Tariff Period (“a fixed revenue cap”), subject to (a) allowances when large transmission capital investments are commissioned, allowed as and when such events occur, and (b) annual adjustments to the Base Allowed Revenue on account of inflation and exchange rate variations.

(iii) Tariffs chargeable by the Distribution and Supply Licensees for the Distribution and Supply business will be based on multi-year tariff principles, where the Base Allowed Revenue for each Distribution Licensee will be capped but vary from year to year over the Tariff Period (“a variable revenue cap”), subject to annual adjustments to the Base Allowed Revenue on account of inflation and exchange rate variations, and variations of the number of customers and amount of energy sold.

(iv) The Commission has determined that (a) the first six-month period for the determination of generation pass-through costs would commence on 1st January 2011, and that (b) the first Tariff Period for the determination of Transmission Licensee’s and Distribution Licensees’ allowed revenues to be five years commencing on 1st January 2011.

(v) To reflect the variations in the allowed generation pass-through costs in each six-month interval, and the Transmission and Distribution allowed revenues once in 12-months, the end-use customer tariffs would be changed once in six months.

(vi) Owing to the limited information available to the Commission to assess the Licensees’ revenue requirements, the Commission has determined that there will be an extraordinary tariff filing by the Transmission Licensee and Distribution Licensees on or before 30th June 2011, for the remaining period of the first Tariff Period (ie 2012-2015), by which time, certified information including audited statement of accounts for each Licensee should be filed with the Commission

(vii) Owing to the requirement to maintain uniform national tariffs to end-use customers, irrespective of varying costs of each Distribution Licensee, the Commission requested each Licensees to file only their revenue requirements. Once the revenue requirements are reviewed and approved, the Commission has used such Allowed Revenues to develop the proposed end-use customer tariffs.

The Commission approved and issued the following time table for the setting of tariffs:

Submission of revenue requirements by the Licensees for the first Tariff Period: 9th September 2010 (completed)

Analysis of revenue requirements, clarifications by Licensees and preparation of the Commission’s proposals: 14th October 2010 (completed)

Period allowed for Public Consultations: 24rd November to 08th December 2010 Public hearing: 15th December 2010 Operational date for new tariffs: 1st January 2011

In fulfilling the relevant sections of Condition 32 of the Transmission and the Bulk Supply License No EL/T/09-002 issued to the Ceylon Electricity Board (CEB), the Transmission Licensee (hereinafter referred to as the TL) has submitted the revenue requirements for the period starting January 2011.

1 available upon request to the Commission or it may be downloaded from www.pucsl.gov.lk


In fulfilling the relevant section of Condition 31 of Electricity Distribution and Supply Licenses, the five Licensees namely

(i) Ceylon Electricity Board in respect of Region 1 holding license number EL/D/09-003 (hereinafter referred to as DL1)

(ii) Ceylon Electricity Board in respect of Region 2 holding license number EL/D/09-004 (hereinafter referred to as DL2)

(iii) Ceylon Electricity Board in respect of Region 3 holding license number EL/D/09-005 (hereinafter referred to as DL3)

(iv) Ceylon Electricity Board in respect of Region 4 holding license number EL/D/09-006 (hereinafter referred to as DL4)

(v) Lanka Electricity Company (Private) Limited holding license number EL/D/09-007 (hereinafter referred to as DL5)

have submitted their respective revenue requirements for the five year period commencing January 2011.

This consultation document is in six parts. The second part presents the key issues on which the Commission invites public comments and the mode in which such comments would be received. The third part presents the Allowed Revenues to each Licensee. The fourth part presents an analysis of Government Subsidies to the sector. The Road Map for Tariff Restructuring and Re-balancing is presented next, to achieve cost-reflective tariffs over 2011-2015. Finally, the sixth part provides the cost of supply of electricity to each customer category, the subsidies and surcharges, and the end-use customer tariffs proposed by the Commission for the first six-month period commencing 1st January 2011.

2. INVITATION FOR PUBLIC COMMENTS

The Commission invites public comments on the following specific proposals listed under each part of this consultation document.

Allowed Revenues for each Licensee

For the Transmission Licensee and for each Distribution Licensee, (i) The sales forecast and allowed losses of each Licensee’s network (2011-2015) (ii) Allowed revenues for each Licensee (2011-2015) (iii) Allowed provision for energy sold for street lighting (2011-2015)

For the Transmission Licensee

(iv) Allowed costs of purchases from generation (v) Allowed provision for purchases from non-dispatchable non-conventional renewable energy-

based generating facilities above the avoided costs of other power plants of the generating system

Road Map for Tariff Restructuring and Rebalancing

(vi) Tariff restructuring in each year to move the customer tariffs towards cost-reflective tariffs (vii) The time intervals proposed for the implementation of mandatory Time of Use (TOU) tariffs (viii) The target of moving the electricity sector to break-even by year 2014 and to profitability by

2015.

Tariffs Payable by Customers from 1st January 2011

(ix) The Tariff Schedule (x) Contents of the monthly statement of account

Public comments may be sent by post or delivered by hand to: Public Utilities Commission of Sri Lanka, Level 6, BOC Merchant Tower, No. 28, St. Michael’s Road, Colombo 03.

Comments may also be sent on email to: [email protected]


3. ALLOWED REVENUES FOR LICENSEES

3.1 SALES FORECAST AND ALLOWED LOSSES

Forecast sales of electricity and the allowed losses in transmission and distribution have an impact on the investments and operating costs of licensees, and on the pass-through costs of electricity generation, all of which will impact the end-use customer tariffs.

3.1.1 SALES FORECAST AND LOSSES FILED BY LICENSEES

Sales forecasts, purchases from the Transmission Licensee (TL) and the loss allowances filed by the Distribution Licensees (DLs) are shown in Table 1. Sales to DLs, purchases from generation and loss allowances filed by the TL are shown in Table 2.

Table 1- Sales Forecasts and Loss Allowances Filed by Distribution Licensees

Purchases (GWh)

Sales (GWh)

Loss Purchases (GWh)

Sales (GWh)


Sales (GWh)


Sales (GWh)


Sales (GWh)

Loss

2009 2,663 2,354 11.6% 3,208 2,734 14.8% 2,033 1,809 11.0% 1,764 1,544 12.5% 1,120 1,030 8.1%2010 2,849 2,519 11.6% 3,421 2,925 14.5% 2,175 1,936 11.0% 1,850 1,628 12.0% 1,232 1,132 8.1%2011 3,003 2,673 11.0% 3,670 3,156 14.0% 2,348 2,090 11.0% 1,868 1,644 12.0% 1,276 1,172 8.1%2012 3,199 2,847 11.0% 3,899 3,361 13.8% 2,501 2,226 11.0% 1,990 1,751 12.0% 1,321 1,214 8.1%2013 3,406 3,032 11.0% 4,143 3,580 13.6% 2,664 2,371 11.0% 2,119 1,865 12.0% 1,367 1,256 8.1%2014 3,628 3,229 11.0% 4,402 3,812 13.4% 2,837 2,525 11.0% 2,257 1,986 12.0% 1,413 1,298 8.1%2015 3,864 3,439 11.0% 4,667 4,060 13.0% 3,021 2,689 11.0% 2,390 2,115 11.5% 1,459 1,341 8.1%

Year

DL2 DL5As filed

DL3 DL4 As filed As filed As filed As filed

DL1

Notes: Loss are given as a % of purchases by each licensee

Table 2- Sales Forecast and Loss Allowances Filed by the Transmission Licensee

Year Sales forecast filed by

TL (GWh)

Input to TL filed by TL

(GWh)

Losses filed by TL (as a % of input)

2010 10,347 10,634 2.70% 2011 10,890 11,185 2.64% 2012 11,559 11,917 3.00% 2013 12,266 12,645 3.00% 2014 13,022 13,424 3.00% 2015 13,802 14,229 3.00%

3.1.2 ADJUSTED SALES FORECAST AND ALLOWED LOSSES

The following corrections were made to the licensee loss allowances:

(a) The Commission reviewed the losses filed for year 2009. The filed sales of CEB DLs was 8441 GWh (including sales to DL5- LECO). On the basis that TL’s losses in year 2009 were 2.7%, the calculated input to the TL’s network would be 9936 GWh. Therefore, the total CEB licensees’ (TL, and DL1, 2, 3 and 4) network loss for 2009 as a share of input to TL would be 15.0%. With the addition of power plant auxiliary power requirements and power plant step-up transformer losses, CEB reported elsewhere, that the total loss was 14.6%, which is significantly lower than the 15.0% transmission and distribution loss implied in the filed losses. This mismatch was corrected by reducing the allowed losses of all CEB DLs for 2009.

(b) The Commission observes the even with the above corrections, the total transmission and distribution network loss of Sri Lanka for year 2009 is estimated to have been 14.2%, which fell short of the policy target of 13.5% in 2009 established in the National Energy Policy and Strategies2.

2 National Energy Policy and Strategies, The Gazette of the Democratic Socialist Republic of Sri Lanka, Extraordinary, No. 1553/10 – TUESDAY, JUNE 10, 2008


(c) The uncorrected losses (as filed) for the total transmission and distribution network in 2015 was 14.4%. The corrected losses indicate a total network loss of 13.3% in 2015. A target of 12% of transmission and distribution losses (as a share of net generation) has been established for year 2016, in the Government’s ten-year plan3. Therefore, allowed losses of all distribution licensees were further adjusted downwards, to enable a target transmission and distribution loss of 12.1% to be met by year 2015.

(d) The losses of the TL as a share of input to the TL’s network were allowed as filed.

The following corrections were made to the licensee sales forecasts:

(e) The sales forecast filed by the TL for 2012-2015 did not match with the purchases filed by DL1, 2, 3 and 4, who are direct customers of TL. This mismatch was corrected, considering at this stage, that DLs’ purchase forecasts are correct.

(f) The sale growth forecasts for DL1, 2, 3 and 4 for year 2010 were in the range of 5.5% to 7.0%, whereas DL5 forecast a 9.9% growth. Sales by DL1, 2, 3 and 4 were increased to represent a more realistic 7.9% growth for all sales in Sri Lanka in year 2010.

(g) DL5 has filed some of the sales for street lighting as losses. Based on the response to a clarification, this was corrected and identified under sales.

(h) DL4 has filed a lower sales growth for year 2011 of 1.0%, which was corrected to 5.0%.

Accordingly, in setting tariffs, the Commission proposes to establish the allowed forecast and allowed losses as shown in Table 3.

Table 3- Allowed Sales, Purchases and Losses

Year

DL1 As filed Corrected

Purchases (GWh)

Sales (GWh)

Sales growth

Loss

Purchases (GWh)

Sales (GWh)

Sales growth

Allowed loss

2009 2,663 2,354 11.6% 2,614 2,354 10.0% 2010 2,849 2,519 7.0% 11.6% 2,828 2,547 8.2% 10.0% 2011 3,003 2,673 6.1% 11.0% 2,983 2,704 6.2% 9.3% 2012 3,199 2,847 6.5% 11.0% 3,164 2,882 6.6% 8.9% 2013 3,406 3,032 6.5% 11.0% 3,360 3,071 6.6% 8.6% 2014 3,628 3,229 6.5% 11.0% 3,568 3,272 6.5% 8.3% 2015 3,864 3,439 6.5% 11.0% 3,797 3,486 6.5% 8.2%

Year


Purchases (GWh)

Sales (GWh)

Sales growth

Loss

Purchases (GWh)

Sales (GWh)

Sales growth

Allowed loss

2009 3,208 2,734 14.8% 3,149 2,734 13.2% 2010 3,421 2,925 7.0% 14.5% 3,396 2,958 8.2% 12.9% 2011 3,670 3,156 7.9% 14.0% 3,645 3,193 8.0% 12.4% 2012 3,899 3,361 6.5% 13.8% 3,858 3,403 6.6% 11.8% 2013 4,143 3,580 6.5% 13.6% 4,074 3,626 6.6% 11.0% 2014 4,402 3,812 6.5% 13.4% 4,311 3,863 6.5% 10.4% 2015 4,667 4,060 6.5% 13.0% 4,573 4,116 6.5% 10.0%

3 A Ten-year Horizon Development Framework 2006-2016, Department of National Planning, Ministry of Finance and Planning


Year


Purchases (GWh)

Sales (GWh)

Sales growth

Loss

Purchases (GWh)

Sales (GWh)

Sales growth

Allowed loss

2009 2,033 1,809 11.0% 1,995 1,809 9.3% 2010 2,175 1,936 7.0% 11.0% 2,159 1,957 8.2% 9.3% 2011 2,348 2,090 8.0% 11.0% 2,332 2,115 8.1% 9.3% 2012 2,501 2,226 6.5% 11.0% 2,474 2,253 6.6% 8.9% 2013 2,664 2,371 6.5% 11.0% 2,627 2,401 6.6% 8.6% 2014 2,837 2,525 6.5% 11.0% 2,790 2,558 6.5% 8.3% 2015 3,021 2,689 6.5% 11.0% 2,969 2,726 6.5% 8.2%

Year


Purchases (GWh)

Sales (GWh)

Sales growth

Loss

Purchases (GWh)

Sales (GWh)

Sales growth

Allowed loss

2009 1,764 1,544 12.5% 1,732 1,544 10.9% 2010 1,850 1,628 5.5% 12.0% 1,836 1,646 6.6% 10.4% 2011 1,868 1,644 1.0% 12.0% 1,930 1,730 5.1% 10.4% 2012 1,990 1,751 6.5% 12.0% 2,051 1,843 6.6% 10.1% 2013 2,119 1,865 6.5% 12.0% 2,173 1,964 6.6% 9.6% 2014 2,257 1,986 6.5% 12.0% 2,305 2,093 6.5% 9.2% 2015 2,390 2,115 6.5% 11.5% 2,440 2,230 6.5% 8.6%

Year


Purchases (GWh)

Sales (GWh)

Sales growth

Loss

Purchases (GWh)

Sales (GWh)

Sales growth

Allowed loss

2009 1,120 1,030 8.1% 1,120 1,051 6.2% 2010 1,232 1,132 9.9% 8.1% 1,231 1,155 9.9% 6.2% 2011 1,276 1,172 3.6% 8.1% 1,273 1,198 3.7% 5.9% 2012 1,321 1,214 3.6% 8.1% 1,314 1,241 3.6% 5.6% 2013 1,367 1,256 3.5% 8.1% 1,357 1,284 3.5% 5.4% 2014 1,413 1,298 3.3% 8.1% 1,399 1,327 3.3% 5.2% 2015 1,459 1,341 3.3% 8.1% 1,442 1,370 3.3% 5.0%

Year

TL As filed Corrected

Purchases (GWh)

Sales (GWh)

Sales growth

Loss

Purchases (GWh)

Sales (GWh)

Sales growth

Allowed loss

2009 9,754 9,491 2.7% 2010 10,347 10,634 2.7% 10,503 10,219 7.7% 2.7% 2011 10,890 11,185 5.2% 2.6% 11,185 10,890 6.6% 2.6% 2012 11,559 11,917 6.5% 3.0% 11,903 11,546 6.0% 3.0% 2013 12,266 12,645 6.1% 3.0% 12,612 12,233 6.0% 3.0% 2014 13,022 13,424 6.2% 3.0% 13,375 12,974 6.1% 3.0% 2015 13,802 14,229 6.0% 3.0% 14,206 13,780 6.2% 3.0%

Year

Total TL and all DL networks Policy target for Sri Lanka T&D

losses

As filed Corrected Sales to End-use

Customers (GWh)

Sales growth

Input to TL's

network (GWh)

Sri Lanka T&D Loss

Sales to End-use

Customers (GWh)

Sales growth

Input to TL's

network (GWh)

Sri Lanka T&D Loss

2009 8,351 8,371 - 9,754 14.2% 13.5% 2010 8,908 6.7% 10,634 16.2% 9,031 7.9% 10,503 14.0% 2011 9,460 6.2% 11,185 15.4% 9,667 7.0% 11,185 13.6% 2012 10,078 6.5% 11,917 15.4% 10,308 6.6% 11,903 13.4% 2013 10,736 6.5% 12,645 15.1% 10,989 6.6% 12,612 12.9% 2014 11,437 6.5% 13,424 14.8% 11,713 6.6% 13,375 12.4% 2015 12,184 6.5% 14,229 14.4% 12,485 6.6% 14,206 12.1% 12.1% 2016 12.0%


3.2 ALLOWED COSTS OF LICENSEES

The Commission observes that the present tariff setting is the first such setting of tariffs after the licenses were issued in October 2009. Four of the five licenses for distribution are held by Ceylon Electricity Board (CEB). The Transmission License is also held by CEB. As CEB operated as a single, vertically integrated utility until the licenses were issued, annual accounts of the functional business units that hold each license have not been previously prepared. A condition in the license is the requirement to prepare and submit audited accounts annually to the Commission. Similarly, the capital expenditure program for at least five years ahead is required to be submitted to the Commission for approval.

In this Tariff Setting, the Commission intends to waive these two requirements, and has determined that, (a) a capital expenditure program should be filed by each licensee for Commission approval, by March 2011, (b) annual audited accounts of year 2010 should be submitted by each licensee by June 2011, and considering the limitation of information currently available for the current tariff setting that, (c) an extraordinary tariff setting will be conducted in 2011 in which the licensees would file their revenue requirements for the period 2012-2015 for the approval of the Commission.

3.2.1 DEBT RESTRUCTURING OF CEB LICENSEES Prior to commencing the tariff setting and associated procedures, the Commission conducted a detailed assessment of likely costs of each licensee, including the costs of generation, and made such information available to the Ministry of Finance and Planning, and to the Ministry of Power and Energy. The analysis indicated that CEB licensees would continue to make losses if the present Tariff Order of the Commission, issued in April 2009, continues to be applied. In June 2010, the Commission provided several scenarios of reforms to customer tariffs, to enable the licensees to move to profitability over the period 2011-2015. The Commission observed that the costs of generation would continue to increase in real terms until 2013, and would decline thereafter, with the commissioning of stages 2 and 3 of the Puttalam coal-fired power plant and the Trincomalee coal-fired power plant. The Commission thus briefed the Government (i) on the large burden of servicing the debts of DL1, 2, 3, 4 and the TL, and (ii) the need to cushion the costs of the CEB licensees, directly or indirectly, if their impacts on customer prices are to be managed within reasonable limits, particularly over 2011-2013. In assessing the costs of debt, the Commission is guided by the certified minutes of a meeting held at the Ministry of Finance and Planning on August 6, 2010, chaired by Secretary to the Treasury. The minutes have been circulated to all the CEB licensees and the Commission. The minutes state, under item (3) a. “Total outstanding debt stock (of CEB licensees) to the Treasury and (Ceylon Petroleum Corporation) CPC as at 31.12.2009 should be considered as zero. In other words, as at 01.01.2010 CEB has no outstanding debt”. Under the same treasury meeting referred to above, it is noted under item (3) c. “The servicing of debt including repayment of capital and interest for the investment of about US$3bn (made by the government) during the period from 01.01.2010 – 31.12.2013 should be borne by CEB. However, CEB need not bear the cost of interest for the investment made by the government prior to 31.12.2009. Until a decision is taken, for the purpose of the tariff calculation the interest cost should not be considered”. The Commission therefore, requested CEB licensees to take note of the above when filing their revenue requirement for the period 2011-2015. The Government, however, has not provided guidance on restructuring of CEB licensees’ short-term debts.

3.2.2 COSTS OF DISTRIBUTION LICENSEES

The five distribution licensees were provided with a template to submit their costs. The template follows the principles stated in the approved Methodology for Tariffs. In addition, the licensees were requested for additional supporting information.

Initially, all the templates were corrected for inaccuracies in formulae. Thereafter, supporting information provided by each licensee was evaluated and the required adjustments were made to the costs. The following is a list of such adjustments done.


Distribution Licensees (DL1, 2, 3 and 4):

(i) Long term debts: These commitments (capital repayments and interest payable thereon, and interest during construction on loans for on-going capital expenditure projects) had been filed by CEB licensees, in spite of the debt restructuring plan stipulated by the Government (see section 3.2.1). These were removed from the filed costs, and the Licensees were requested to provide a schedule of restructured debts that would be required to be serviced from 2014 onwards. This schedule has not been received, and therefore, the present tariff setting has no provision for servicing long-term debts even after the debt moratorium allowed by the Treasury explained in section 3.2.1 ends in 2013. The Commission proposes to consider any such debts filed and associated interest payments, during the extraordinary tariff setting scheduled to commence in June 2011, if the details of such debts are filed.

(ii) Short-term debts: Licensees have filed the cost of repayment of short-term debts, as “headquarters overheads”. The Commission observes that such inclusion would cause the distribution licensee costs to be distorted. The Commission proposes to include such debt recovery as a levy under the generation pass-through costs (please see further details in section 3.2.7).

(iii) Other revisions: (a) Operating expenditure (OPEX) and capital expenditure (CAPEX) were mixed in certain filings,

and these were adjusted accordingly. Similarly, VAT and customs duty components associated with such expenditure were adjusted.

(b) The salary increase of 21.6% included in the filing was allowed for year 2012, considering the submission that salaries have not been increased in 2010. Thereafter, the salaries remain constant until 2014. From 2015 onwards, salary increases have been adjusted to be 3.5% in real terms. The same was applied in assessing the costs of salaries at the headquarters of each licensee.

(c) Non Salary OPEX was adjusted to increase at the same rate as the customer growth percentage filed by the licensees.

(d) The non-salary overhead I (Regional Head Quarters Overhead) costs of licensees have been corrected to remain constant in real terms throughout the tariff period, at the level filed for 2010.

(e) Following information obtained from licensees, the non-amortized customer contribution was removed from the asset base and included as a separate line item in the revenue template for calculations

(f) The filed CAPEX allowance for new vehicles was decreased by 50% (from 2011 onwards) as an interim measure, pending a comprehensive review during the approval process of the CAPEX program due in March 2011. The forecast depreciation was adjusted accordingly.

(g) OPEX of the retail business was adjusted to increase at the same rate as the customer growth percentage

(h) Income from sales to street lighting was removed from bad debts.

Distribution licensee DL5:

(i) Salaries of DL5 (LECO) were allowed a 8.5% real increase in 2011, and thereafter, a 3.5% real increase annually over 2012-2015 was allowed.

(j) Non Salary OPEX was adjusted to increase at the same rate as the customer growth percentage filed by the licensees.

(k) The non-salary Head Quarters overhead costs have been corrected to remain constant in real terms throughout the tariff period, at the level filed for 2010.

(l) Following information obtained from the licensee, the non-amortized customer contribution was removed from the asset base and included as a separate line item in the revenue template for calculations

(m) CAPEX allowance for new vehicles have been decreased by 50% as an interim measure, pending a comprehensive review during the approval process of the CAPEX program due in March 2011. The depreciation forecast was adjusted accordingly.

(n) OPEX of the retail business was adjusted to increase at the same rate as the customer growth percentage

(o) Bad debts were adjusted by taking out the sales to street lighting, as provided by the licensee, and added that component as sales.


Filed Revenue Requirements and Allowed Revenues proposed by the Commission are summarised in Table 4.

Table 4- Distribution and Retail Revenues Filed and Allowed Revenues

As filed by the Licensee

Distribution Licensee 1 (DL1) Unit 2011 2012 2013 2014 2015

Distribution Allowed RevenueDistribution Variable Revenue Cap LKR million 8,014.4 8,384.5 8,750.6 9,113.5 9,511.0

Retail Service Allowed RevenueRetail Service Price Cap LKR/customer 428.4 428.4 428.4 428.4 428.4

Total Revenue SummaryDistribution LKR million 8,014.4 8,384.5 8,750.6 9,113.5 9,511.0 Retail Service LKR million 550.8 576.4 602.5 626.8 655.2 TOTAL LKR million 8,565.2 8,960.9 9,353.1 9,740.3 10,166.3

Distribution revenue per MWh sold LKR/MWh 2,963.9 2,909.3 2,849.4 2,785.3 2,728.4 Distribution revenue per customer served LKR/customer 6,234.5 6,214.0 6,214.5 6,233.9 6,233.8

Proposed by the Commission






All renevues are in constant January 2011 currency




Retail Service Allowed RevenueRetail Service Price Cap LKR/cust 551.2 551.2 551.2 551.2 551.2

Total Revenue SummaryDistribution LKR million 8,147.4 8,524.7 8,918.7 9,294.6 9,686.8 Retail Service LKR million 835.1 870.2 917.0 959.8 1,004.3 TOTAL LKR million 8,982.5 9,394.9 9,835.7 10,254.4 10,691.0


















































3.2.3 COSTS OF THE TRANSMISSION LICENSEE

The Transmission Licensee (TL) has two business operations, namely (i) the Transmission Business (ii) the Bulk Supply and Operations Business (BSOB). In addition, the TL is also the Single Buyer, purchasing from all the Generation Licensees (GLs). In this sub section, the Transmission and BSOB businesses are discussed. The single buyer’s business is discussed in the next sub section.

Initially, the TL’s template was corrected for inaccuracies in formulae in the base template provided by the Commission. Thereafter, supporting information provided by the TL was evaluated and the required adjustments were made to the costs. The following is a list of such adjustments done.

(a) Long term debts: These commitments were removed on the same basis as for DL1, 2, 3 and 4, as previously explained.

(b) Short-term debts: These were removed to be included as a levy in the Single Buyer’s pass-through costs, as previously explained.

(c) Work-in-Progress: A large Work-in-progress (WIP) for on-going projects was observed. This was allowed, subject to certain projects on which information was not available. Projects that were not part of the transmission or BSOB, were removed. VAT and financial costs were adjusted accordingly.

(d) In OPEX, with the absence of detailed information, it was assumed that 50% of filed OPEX would be for salaries, which were allowed to escalate on the basis that a salary increase of 21.6% was allowed for year 2012, considering the submission that salaries have not been increased in 2010. Thereafter, the salaries remain constant until 2014. From 2015 onwards, salary increases have been adjusted to be 3.5% in real terms. The same was applied in assessing the costs of salaries at the headquarters of the licensee.

(e)It was assumed that 60% of the OPEX filed for Transmission Overheads were salaries, which were allowed on the same basis as above.(f)CEB Corporate Overheads included a provision for the settlement of short-term loans. This was removed as described earlier.

Table 5 shows the filed Revenue Requirements and Allowed Revenues proposed by the Commission.


Table 5- Transmission and BSOB Revenues Filed and Allowed Revenues


Unit 2011 2012 2013 2014 2015Transmission Allowed Revenue

Transmission Revenue Cap LKR million 9,293.7 9,293.7 9,293.7 9,293.7 9,293.7 Bulk Supply and Operations Business Allowed RevenueBSOB Revenue Cap LKR million 207.0 207.0 207.0 207.0 207.0 Total Revenue SummaryTransmission LKR million 9,293.7 9,293.7 9,293.7 9,293.7 9,293.7 BSOB LKR million 207.0 207.0 207.0 207.0 207.0

TOTAL LKR million 9,500.7 9,500.7 9,500.7 9,500.7 9,500.7

Revenue per MWh served LKR/MWh 830.9 779.9 735.0 692.3 653.2

Revenue per kW LKR/kW 4,130.6 3,883.7 3,664.7 3,473.0 3,279.4


Unit 2011 2012 2013 2014 2015Transmission Allowed Revenue

Transmission Revenue Cap LKR million 7,163.7 7,163.7 7,163.7 7,163.7 7,163.7 Bulk Supply and Operations Business Allowed RevenueBSOB Revenue Cap LKR million 124.6 124.6 124.6 124.6 124.6 Total Revenue SummaryTransmission LKR million 7,163.7 7,163.7 7,163.7 7,163.7 7,163.7 BSOB LKR million 124.6 124.6 124.6 124.6 124.6

TOTAL LKR million 7,288.3 7,288.3 7,288.3 7,288.3 7,288.3

Revenue per MWh served LKR/MWh 640.5 601.1 566.5 533.6 503.5

Revenue per kW LKR/kW-year 3,183.9 2,993.6 2,824.8 2,677.0 2,527.8 All renevues are in constant January 2011 currency

3.2.4 REVENUE REQUIREMENTS OF THE SINGLE BUYER

As stated in the approved Methodology for Tariffs, the Single Buyer costs are filed for a period of six months (January to June). The Commission has the following observations and the corresponding revisions were made to the filed revenues.

(a) Power Purchase Agreements (PPAs) between the Transmission Licensee and CEB Generation Licensee (CEB GL): PPAs between TL and CEB GL with respect to each power plant have not been submitted to the Commission for review and approval, as required in the Methodology for Tariffs. The Commission observes that depreciation of full generation assets has been included in the capacity charges of CEB GL’s power plants. As all the long-term debts have been written off or restructured, CEB GL has no debt repayment or interest commitments in year 2011. Hence there is no justification to charge the full cost of depreciation on CEB GL’s power plants on customers.

Therefore, the Commission proposes to remove the provision for depreciation included in CEB GL’s power plant capacity charges. Accordingly, a sum of LKR 6681 million estimated to have been filed as depreciation charges for year 2011 was removed from the Single Buyer’s filed generation capacity charges.

However, the investments on these power plants may have included a certain amount of CEB’s equity, which has to be returned over a period of time. Based on information available to the Commission, the value of CEB generation assets were estimated to be LKR 267,000 million, on which CEB’s equity was assumed to be 20%. The Government or CEB have not indicated a desire to earn a return on equity on this investment.

As a means of providing a return of equity (not return on equity) over a period of 40 years, a sum of 2.5% of the estimated equity was allowed annually. Accordingly, a sum of LKR 1336 million in


2011 was provided for the purpose of return of equity, and added to the Single Buyer’s revenue requirements.

The Commission reiterates that this is an interim arrangement, and that the process of filing the PPAs between CEB GLs and TL and approval by the Commission should be completed by 31st December 2010.

(b) Fixed O&M costs of CEB Power Plants: CEB thermal power plant capacity charges filed have a fixed, non-fuel energy charge of about LKR 2 per kWh. The Commission observes that this charge is excessive, but has been allowed pending a more comprehensive analysis during the approval of the CEB GL’s PPAs. The non-fuel energy charge filed for gas turbines at Kelanitissa were not allowed, owing to the low dispatch of the plant.

(c) Start-stop charges have been filed but estimates for the number of starts-stops have not been filed.

(d) Pricing of Petroleum fuels: Fuel Supply Agreements (FSA) were not filed with the Commission. TL provided the most recent invoices or communications with Ceylon Petroleum Corporation stating the prices, and these were used as the basis for fixing the prices of all petroleum fuels used for power generation.

(e) Coal pricing: The Fuel Supply Agreement (FSA) has not been submitted to the Commission. Therefore, the pricing was based on an invoice. The Commission observes the following: VAT has been included for coal, whereas for other fuels, VAT is not applicable. Therefore, VAT was removed from coal pricing. A sum of USD 5.65 per tonne has been included as depreciation and overheads within the price calculation for coal, for which the purpose is unclear. This was not allowed. A comprehensive pricing formula including any indices to which the pricing is linked, requires to be filed along with the next Single Buyer’s filing for the period July-December 2011.

(f) Hydropower Dispatch: The Single Buyer has not stated whether the filed hydropower dispatch would comply with the probability of occurrence of 70% stated in the Methodology for Tariffs. As the full claw-back provisions are available, the Commission has allowed the filed hydropower dispatch, pending further clarification in the extraordinary filing due in June 2011.

(g) Dispatch of the coal-fired power plant: The Commission observes that the coal-fired power plant, operating for the first time in the Tariff Period, has been dispatched only up to an annual capacity factor of 60%. This has been allowed, pending a complete review of the dispatch procedure and limitations before the next filing of the Single Buyer, after the power plant completes its commissioning and reliability testing over the first three months of year 2011.

(h) Un-dispatched power plant: The power plant GT07 has not been dispatched at all during the six-month period covered in the revenue filing of the Single Buyer, and the filing states that spares are not available. Capacity charges for this power plant have been filed, but were removed, pending a final decision by TL and submission of the relevant information to the Commission. An ex-post adjustment would be allowed for this power plant’s capacity charges, should the TL dispatch the power plant within the six-month period under consideration, but with prior approval of the relevant PPA by the Commission.

(i) IPPs not loaded to the rated plant capacity: Some IPPs are not loaded to the full capacity, stated as the “rated or installed capacity” in the respective PPAs submitted to the Commission. The Commission has allowed this situation, pending a final determination before the next filing by the TL for the Single Buyer’s costs.

(j) Northern Power: The IPP identified as Northern Power has a monthly capacity factor of more than 1.0. The Commission observes that (i) this power plant has not been fully commissioned, and (ii) the capacity factor of this power plant, serving the isolated network in the Jaffna peninsula, is likely to be much lower than 1.0. The Commission has assumed that the dispatch is correct, and that the filed capacity is incorrect. The relevant PPA has not been submitted for review.

(k) Non-dispatchable (must-run) power plants: In the dispatch filed with the Commission, the Single Buyer has removed the non-dispatchable (must-run) power plants, all of which are Small Power Producers (SPPs). No costs of these have been filed. Commission’s views on these power plants are stated in the next section.


3.2.5 NON-DISPATCHABLE RENEWABLE ENERGY POWER PLANTS

Upon request from the Commission, TL provided the estimated costs of the non-dispatchable power plants, which are all Non-conventional Renewable Energy (NCRE) based SPPs. The following observations and corrections have been made, before such costs are allowed:

(a) Avoided cost calculations: Calculation of avoided costs for year 2011, for payments to contracts signed before 2007 was not provided. Therefore, the following assumptions were made: avoided cost-based tariff for year 2011 would be LKR/kWh 11.00 (wet season), 12.00 (dry season).

(b) Mismatch between avoided costs paid to hydro and biomass, both of which are paid on the same basis were observed, and corrected.

(c) A biomass power plant in the 3-tier tariff, has a tariff of 22 LKR/kWh, and the rate increases mid-year. This is not possible based on the tariff methodology for NCRE, and the tariff is excessive for this power plant, which is licensed as a power plant of the type “Agricultural and Industrial waste”. The tariff was corrected, and no further revisions will be allowed.

The costs of purchasing non-dispatchable renewable energy power plants, is summarised in Table 6.

Table 6- Filed and Allowed Payments to Non-dispatchable NCRE Power Plants

Type Pricing basis Forecast energy Forecast price Allowed payments Payment on Additional burden on customers

of agreement purchased (GWh) (LKR/kWh) (LKR million) avoided costs (LKR million) (LKR/kWh of

Filed Corrected Filed Corrected Corrected (LKR million) end-use sales)

Minihydro Avoided cost 188.0 197.7 11.98 11.50 2,273 2,273 0.0 0.00

3-tier 9.6 10.1 14.27 11.77 119 116 2.7 0.00

Biomass Avoided cost 1.2 1.3 14.00 11.50 15 15 0.0 0.00

3-tier 12.0 12.6 22.00 9.90 125 145 -20.2 -0.00

Wind 3-tier 46.0 48.4 24.73 23.58 1,140 556 584.2 0.12

Total 256.8 270.0 3,672 3,105 566.8 0.12

Note: The above information is for the six-month period January to June 2011.

The Single Buyer has not submitted to the Commission, the manner in which the costs of the SPPs could be met. Considering the filed budget of LKR 8969 million for year 2011 for the purchase of 620 GWh (14.46 LKR/kWh), the Commission is of the view that there should be clarity on how these costs are to be met. As these power plants are non-dispatchable, the Single Buyer has no option to refuse energy from these power plants, but to purchase from them, even when there can be other generators which could produce electricity cheaper than 14.46 LKR/kWh.

As an interim measure, the Commission proposes allowing a levy on the Single Buyer’s energy costs, which would be transparently passed-on to end-use customers. This levy would be allowed on the basis that the Single Buyer would

(i) fully disclose the detailed tariff schedule for payments to each SPP, in conformity with the instructions issued by the Ministry of Power and Energy from time to time, and the announcements made by Sri Lanka Sustainable Energy Authority from time to time, which have already been made available to this Commission

(ii) submit the detailed calculation of avoided costs payable to some of the SPPs for year 2011

and pending a Government policy guideline on

(iii) how the costs of SPPs are to be met in the future (iv) any caps on the quantity and price paid to such purchases (v) any caps on what portion of such costs should be passed-on to electricity customers

The levy on the SB’s pass-through costs allowed for non-dispatchable renewable energy power plants will be withdrawn, unless the above conditions are met by the SB and the Government’s Policy Guidelines are received before the next SB’s filing, due in May 2011 for the period July – December, 2011.

In addition a ‘Green Tariff’ is proposed for industrial consumers who desire to purchase green energy for their products, to recover at least part of this additional cost. A premium of Rs. 3.00/ KWh over and above their unit rate is proposed.


3.2.6 ALLOWED REVENUES OF THE SINGLE BUYER

The allowed revenues of the Single-buyer (inclusive of the Transmission and BSOB), after the making the revisions stated in section 3.2.5 are shown in Table 7.

Table 7- Allowed Revenue of the Single Buyer (incl Transmission and BSOB) Capacity Charge

Month Unit 1 2 3 4 5 6

Capacity ChargeGeneration capacity LKR/MW 948,017 951,673 967,379 980,802 943,882 1,005,529

Transmission LKR/MW 272,218 273,215 277,275 277,533 265,322 289,091 Bulk Supply Service LKR/MW 4,735 4,752 4,823 4,827 4,615 5,028

BST (C) LKR/MW 1,224,970 1,229,639 1,249,477 1,263,162 1,213,818 1,299,649

BST (C)6-Month Weighed average LKR/MW 1,246,070

Energy Charge

Month Unit 1 2 3 4 5 6

Interval 1 (day)Transmission Loss Factor B1 % 2.67% 2.67% 2.67% 2.67% 2.67% 2.67%

Generation energy Cost B1 LKR/kWh 7.44 7.12 7.20 6.99 6.52 6.53BST (E1) LKR/kWh 7.64 7.31 7.40 7.18 6.69 6.71

Interval 2 (peak)Transmission Loss Factor B2 % 3.41% 3.41% 3.41% 3.41% 3.41% 3.41%


Interval 3 (off-peak)Transmission Loss Factor B3 % 1.89% 1.89% 1.89% 1.89% 1.89% 1.89%


Economic dispatch

ST debt recovery

Renewable energy above avoided costs

Total BST (E)

BST day (E1)6-Month weighed average LKR/kWh 7.16 0.52 0.11 7.78

BST peak (E2)6-Month weighed average LKR/kWh 9.37 0.52 0.11 10.00

BST off-peak (E3)6-Month weighed average LKR/kWh 4.97 0.52 0.11 5.60

Special Levies on BST (included in all intervals above)

LKR million 2800.0

LKR million 566.0

Total commitment on ST debts for the periodLevy on NCRE purchases in excess of avoided costs BST = Bulk Supply Tariff. These refer to the tariff at which electricity will be sold by the TL to DLs, or to any customers purchasing direct from the TL. NCRE = Non-conventional Renewable Energy, which are non-dispatchable

3.2.7 PROVISION FOR THE SETTLEMENT OF SHORT-TERM DEBTS

As explained earlier, CEB Licensees (DL1-4) and TL filed for a recovery of costs to service the short-term debts, by embedding such costs in overheads. Upon clarification by the Commission, these were identified and separated out. Table 8 shows the calculated profile of debt service, to settle these short-term debts, estimated by the Commission based on the CEB licensee responses to clarifications.

Table 8-Filed Provisions to Settle Short-term Debts of CEB Licensees

Year 2010 2011 2012 2013 2014 2015

Total debt service (LKR

million)

5,345

5,600

4,055

1,335

885

790


The Commission observes that

(i) information provided is inadequate, whereas, the details of each loan, its repayment schedule, interest payments and interest rates, should have been provided for each month of the five year Tariff Period.

(ii) copies of the relevant loan agreements should be filed with the Commission

(iii) a statement on how the CEB Licensees would negotiate with the lenders, to gain advantage of the declining interest rates is required, and

(iv) any actions that would enable the short-term debts to be converted to long-term debts or other financial instruments, to smoothen the impacts on customers, should be provided

To repay these short-terms debts, the Commission proposes to place a special levy on the pass-through costs of the Single Buyer, which will be transparently passed-on to customers, and included in the Bulk Supply Tariff and finally, in the end-use customer tariffs. The Commission would establish regulatory oversight on the short-term debts, and pass-on any changes to the customers, in each six-monthly revisions of the Bulk Supply Tariffs.

The amount of this levy to be recovered over the period January to June 2011 is proposed to be LKR 2800 million, with a full claw-back provision for any variations. If the relevant information described earlier in this section is not provided, the levy would be completely withdrawn in the next determination of the Single Buyer’s pass-through tariffs due for the period July-December 2011.

3.3 ANALYSIS OF COSTS OF LICENSEES

Table 9 shows an analysis of the costs of supply, considering the revenue allowances proposed to be approved by the Commission.

Table 9- Analysis of Allowed Costs of Transmission and Distribution Services

Licensee 2011 2012 2013 2014 2015

Revenue cap (LKR million) DL1 6,981 7,303 7,623 7,939 8,286 DL2 7,956 8,318 8,706 9,073 9,455 DL3 4,657 4,859 5,073 5,292 5,517 DL4 3,776 3,926 4,056 4,187 4,318 DL5 2,514 2,581 2,663 2,729 2,780 Distribution Total 25,883 26,988 28,122 29,220 30,356 TL 7,288 7,288 7,288 7,288 7,288 Total 33,172 34,276 35,411 36,509 37,645 Sales Forecast (GWh) 9,667 10,308 10,989 11,713 12,485 Sales by each Licensee (GWh) DL1 2,704 2,882 3,071 3,272 3,486 DL2 (including sales to DL5) 3,193 3,403 3,626 3,863 4,116 DL3 (including sales to DL5) 2,115 2,253 2,401 2,558 2,726 DL4 (including sales to DL5) 1,730 1,843 1,964 2,093 2,230 DL5 1,198 1,241 1,284 1,327 1,370 Distribution Total 9,667 10,308 10,989 11,713 12,485 TL 10,890 11,546 12,233 12,974 13,780 Cost of Service (LKR/kWh sold by each licensee) DL1 2.58 2.53 2.48 2.43 2.38 DL2 (including sales to DL5) 2.49 2.44 2.40 2.35 2.30 DL3 (including sales to DL5) 2.20 2.16 2.11 2.07 2.02 DL4 (including sales to DL5) 2.18 2.13 2.06 2.00 1.94 DL5 2.10 2.08 2.07 2.06 2.03 Distribution Total 2.68 2.62 2.56 2.49 2.43 TL 0.67 0.63 0.60 0.56 0.53 Total T&D cost (LKR/kWh sold) 3.43 3.33 3.22 3.12 3.02

The Commission observes that with the allowed revenues, the total Sri Lanka transmission and distribution costs would decrease in real terms over the five-year tariff period 2011-2015. Table 10 describes the structure of costs applicable for the period January-June 2011.


Table 10- Composition of the Costs to end-users (January - June 2011)

For a period of six months Units Value Notes

System costs

Total DL costs LKR million 12,942 50% of annual revenue cap

TL LKR million 3,644 50% of annual revenue cap

Single Buyer's capacity costs LKR million 12,551 Allowed cost Single Buyers energy costs LKR million 38,507 Allowed cost

Levies Provision for Short-term debts LKR million 2800

Allowed levy, interim and conditional

NCRE above avoided costs LKR million 566 Allowed levy, interim and conditional

Total LKR million 71,010

Six months' sales as a share of annual 49.1% Sales for the six-month period GWh 4,748 Average Price to end-user LKR/kWh sold 14.95

Note: For an assessment of direct and indirect Government subsidies not reflected in the above costs, please see section 4.

Table 11- Analysis of the Cost Break-up of end-users

Cost component Cost LKR/kWh sold Distribution and Retail 2.73 Transmission and BSOB 0.77 Generation capacity 2.64 Generation energy 8.11 Levy for short-term debts 0.59 Levy for renewable energy 0.12 Total 14.95

Note: For an assessment of direct and indirect Government subsidies not reflected in the above costs, please, see section 4.

4. GOVERNMENT SUBSIDIES

4.1 LONG-TERM DEBTS WRITTEN-OFF AND RESCHEDULED

The Commission has undertaken as assessment of the value of debts written-off, and the avoided payments to the Government to service the debts of on-going investments, including interest during construction. These estimates are provided in Table 12.

Table 12- Evaluation of the Government Subsidy owing to Long-term Debt Relief

All costs are in LKR million Interest Payment Position (long-term loans) Year 2011 Laxapana 107 Mahaweli 74 Other Hydro 151 Thermal 8,392 Sub total (CEB GL) 8,724 Transmission (wires) 3,601 CEB DLs 4,529 All CEB Licensees 16,854 Capital Repayments (long-term loans) Year 2011 Laxapana 69 Mahaweli 3 Other Hydro 572 Thermal 1,997 Sub total (CEB GL) 2,641 Transmission (wires) 2,297 CEB DLs 862 All CEB Licensees 5,800 CEB Licensee debt service (long-term loans) 22,654


4.2 CONCESSIONS ON FUEL PRICES

The Commission has assessed that the following fuels used in both CEB and IPP generating facilities are provided at a concessionary price at the time of the filing.

(i) Fuel oil 180 cSt (1500 s) for CEB and IPPs: price 42.55 LKR/litre (ii) Fuel oil 380 cSt (3500 s) for CEB and one IPP: price 40.00 LKR/litre (iii) Fuel oil (low sulphur, for West Coast Power Plant): price 52.00 LKR/litre

Based on the evidence of pricing submitted by the Single Buyer, the Commission is of the view that three other fuels used for generation (coal, auto diesel and naphtha) are priced adequately close to the international prices, adjusted by the cost of freight and other charges.

The Commission estimates that the fuel subsidy for the period of six-months over January – June 2011 to be LKR 8524 million. In the absence of information filed by the Single Buyer or their fuel supplier(s), this subsidy is an estimate.

Table 13- Composition of Costs including Government Subsidies

For a period of six months Units Value

Cost LKR per kWh sold

Share of each cost including

Govt subsidies

Share of average

cost excluding

Govt subsidies

System costs

Allowed total DL costs LKR million 12,942 2.73 14.2% 18.2% Allowed TL costs LKR million 3,644 0.77 4.0% 5.1% Single Buyer's allowed capacity costs LKR million 12,551 2.64 13.8% 17.7%

Single Buyers allowed energy costs LKR million 38,507 8.11 42.4% 54.2%

Levies Allowed provision for Short-term debts LKR million 2800 0.59 3.1% 3.9%

Allowed NCRE above avoided costs LKR million 566 0.12 0.6% 0.8%

Sub total Costs to be recovered through tariffs LKR million 71,010 14.95 78.2% 100.0%

Government Subsidies

Relief from long-terms debts LKR million 11,327 2.39 12.5% Concession on fuel prices LKR million 8,524 1.80 9.4%

Total 90,860 19.14 100.0%

Six month sales as a share of annual sales 49.1%

Sales GWh 4,748

Average Cost inclusive of Govt subsidies LKR/kWh 19.14

Note: The period covered is January – June 2011

The Commission estimates that the actual cost of the electricity industry in year 2011 would be LKR 19.14 per kWh sold, which has been subsidised by an extent of 21.9% (LKR 4.19 per kWh) by the Government through (i) the debt write-off and the moratorium, and (ii) concessionary pricing of fuel prevailing as of the filing date by the licensees.

4.3 PROCEDURE IF SUBSIDIES OR CONCESSIONS ARE CHANGED

If for any reason, the Government subsidies listed above are not received by the Single Buyer in full, the ex-post correction provisions in the approved Methodology for Tariffs will be applied and the Single Buyer will be compensated accordingly, and any expenses would be passed on to customers, as provided in the approved Methodology for Tariffs.

Similarly, if the Single Buyer receives any direct or indirect subsidies other than those listed above, such subsidies would be clawed back and passed-on to customers as a discount, as provided in the approved Methodology for Tariffs.


5. ROAD MAP FOR TARIFF REBALANCING

5.1 INTRODUCTION

Cost to supply each group of consumers were calculated using a technical loss allocation methodology and it has been found that end-use customer tariffs at present are not cross-reflective. Certain classes of customers are subsidised, while others pay a surcharge to finance the cross subsidy. The electricity sector is considered to need LKR 34,293 million in direct and indirect subsidies. Removal of cross-subsidies among electricity customers and gross subsidies to the sector, requires a step-by-step approach, considering its socio-economic implications.

Table 14- Costs of Supply and Subsidies Required in Year 2011 if Present Tariffs Continue

Customer Category Total Sales (GWh)

Total Cost (LKR

million)

Total revenue

(LKR million)

Total (Subsidy) or surcharge

on customers

(LKR million)

Cost of supply(LKR/kWh)

Forecast revenue

(LKR/kWh)

Households 0-30 233 5,518 1,113 (4,405) 23.66 4.77 31-60 756 15,928 3,695 (12,233) 21.07 4.89 61-90 1,018 20,093 5,974 (14,119) 19.73 5.87 91-180 1,254 22,225 14,973 (7,252) 17.72 11.94 181-600 492 8,346 9,957 1,611 16.98 20.26 >600 100 1,479 3,561 2,082 Sub Total 3,853 73,590 39,273 (34,317) 19.10 10.19 Other LV Religious 57 1,004 513 (491) 17.65 9.02 General Purpose 1 1,149 15,809 23,943 8,134 13.76 20.83 Industrial 238 3,171 2,611 (561) 13.32 10.96 Hotel 1 19 20 1 15.01 15.73 Street Lighting 148 2,292 3,668 1,376 15.43 24.70 Sub Total 1,594 22,295 30,754 8,460 13.99 19.29 LV BULK - General Purpose 2 875 9,751 18,555 8,803 11.14 21.20 Industrial 2 1,561 19,899 19,444 (455) 12.75 12.46 Industrial 2 TOU 174 2,159 2,343 184 12.41 13.47 Hotels 2 TOU 2 26 30 4 11.10 12.60 Hotels 2 (GP) 73 824 1,169 345 11.21 15.91 Hotels 2 (IP) 54 656 625 (31) 12.25 11.67 Sub Total 2,739 33,315 42,165 8,850 12.16 15.39 MEDIUM VOLTAGE - General Purpose 3 223 2,263 4,378 2,115 10.13 19.61 Industrial 3 1,035 10,965 11,661 697 10.59 11.26 Industrial 3 TOU 143 1,376 1,721 345 9.64 12.06 Hotels 3 8 77 83 6 9.66 10.44 Hotel 3 TOU 71 629 725 95 8.89 10.24 Sub Total 1,480 15,310 18,569 3,259 10.34 12.55 Total 9,666 144,510 130,761 (13,749) 14.95 13.53

The Commission observes that

(i) based on the review of licensee costs and allowed revenues described in previous sections of this consultation document,

(ii) giving due recognition to the Government for the relief from long-term debts and the currently applicable concessionary prices on fuel,

(iii) allowing levies to recover short-term debts and excessive payments for renewable energy,

there will be a revenue shortfall of LKR 13,749 million in year 2011, if the present end-use customer tariffs continue to apply.

The Commission proposes that to cover the revenue shortfall of LKR 13,749 million (LKR 6874 million for the period January–June 2011), the customer tariffs be restructured with three key objectives:

(i) To increase the total expected revenue by 10.5%, to enable ALL the licensees to be financially independent from any further grants and subsidies by the Government

(ii) To commence a process of tariff rebalancing, which will progressively move the pricing of electricity in Sri Lanka to be cost-reflective by year 2015.

(iii) To commence a process of changing customer tariffs in such a manner that in year 2014, CEB


licensees would meet all commitments, including the payment of long-term debts and interest, and paying cost-reflective prices for all fuels.

(iv) To ensure CEB licensees would be profitable by year 2015. (v) To commence the subsidy provisions to low-income customers, as provided for in the National

Energy Policy and Strategies and the Policy Guidelines of the Ministry of Power and Energy provided to the Commission, and the ten-year development plan of the Government.

5.2 THE ROAD MAP FOR TARIFF REFORMS

The road map for tariff rebalancing and the systematic movement towards cost-reflective tariffs requires changes to customer categories, improvements to metering and managing the price adjustments each year to acceptable levels. Error! Reference source not found. shows the road map proposed by the Commission. This is addition to the proposed removal of Fuel Adjustment Charges.

Table 15- Roadmap for Tariff Rebalancing

Year Households Religious Other retail (industry, general, hotel)

Bulk Consumers

2011 Continue with the lower tariffs for low-income groups

25% reduction

Introduce a category for government schools, hospitals and DS offices.

Time of Use tariffs made mandatory for Industrial consumers Flat tariffs mandatory for other groups of consumers

2012 Reduce the number of blocks

No changes

Reduce the price gap between the classes of customers

All classes of bulk customers to be unified and Time of Use (TOU) tariffs to be mandatory Introduce a charge for reactive power

2013 Reduce blocks No changes

No difference between the customer classes, except in terms of voltage at which service is provided. For the purpose of retaining a database, customer classification will be retained in the accounting system. TOU tariffs will be mandatory for all retail and bulk customers in industry, hotel and general purpose categories Any subsidies will be addressed outside the licensee tariffs.

2014 Retain 3 blocks No changes

No further changes

Optional TOU tariff for all 3-phase customers

No changes

Tariffs yield adequate revenue to breakeven, meet all commitments including debt service, but excluding a return on assets to GOSL

2015 Abolish block tariffs. Optional TOU tariffs to all customers.

No changes

No further changes

Tariffs to all customers are targeted to be fully cost reflective. GOSL earns a return on assets on the sector.

5.3 TIME INTERVALS PROPOSED FOR TOU TARIFFS

The Commission proposes the following time intervals to be used in the implementation of the Time of Use (TOU) tariff to all classes of customer, as described in Error! Reference source not found., as and when each class of customer moves to mandatory (or optional, as stated) TOU tariffs over 2011-2015. These time intervals have been determined on the basis of the load profile on the TL’s network, and the practical considerations of large customers who would be encouraged to operate an additional night shift, to take advantage of the lower tariffs in the off-peak period.

Table 16- Proposed Intervals in the TOU Tariff

Description Code Interval Number of hours Day 1 0530 to 1830 13 Peak 2 1830 to 2230 4


Off-peak 3 2230 to 0530 7

6. PROPOSED TARIFFS

6.1 RECOVERY OF COSTS OF STREET LIGHTING

Distribution Licensees have submitted to the Commission, the issue of bad debts accumulating owing to non-payment for energy used for street lighting. After due consideration of the relevant issues, and to enable the due revenues to be collected by the Licensees and the need for efficient use of electricity in street lighting, the Commission proposes the following arrangement:

(i) The cost of energy used for street lighting will be passed-on to electricity customers as a special charge included in the cost of supply .

(ii) For the period 1st January 2011 to 30th June 2011, the allowed revenue to recovered will be equal to the cost of the forecast sales to street lighting included in the revenue filing by each Distribution Licensee or clarifications submitted to the Commission during the tariff setting process. Please see the proposed allowance for energy sold to street lighting shown in Table 17, which would be final with no provisions for claw-back or additional allowances

(iii) From 1st January 2011, the Distribution Licensees would ensure that street lighting would be served with energy allowed shown in Table 17, and would ensure adequate metering, and other control and monitoring systems will be installed to enable the allowed quantity of energy to be provided, measured and used in the most efficient manner.

(iv) Any existing or new arrangements to provide street lighting to private or public roads and premises, at the request of private individuals or institutions, should not be counted for the street lighting energy allowance, and should be metered and billed as sales at the published tariffs for street lighting

(v) The inclusion of energy costs of street lighting in the customer tariffs does not provide any rights to individuals or institutions to request energy to be provided for street lighting of their choice. This recovery of revenue is allowed on the basis that all customers are benefited by street lighting used anywhere in the country.

(vi) The allowed energy served to street lighting should only be for street lights approved by the Local Authority or such authority as the Road Development Authority.

(vii) To enable the Commission to re-asses the energy served to street lighting, Distribution Licensees are required to submit to the Commission, a statement on the number and type of street lamps, their operating hours and energy served to each Local Authority area, certified by the relevant Local Authority or other relevant authority such as the Road Development Authority. These certified statements should be provided to the Commission along with the extraordinary tariff filing scheduled for June 2011.

(viii) The cap on the energy sold to street lighting that will be allowed for recovery through this mechanism by each Distribution Licensee in the tariff filing in June 2011, for the period 2012-2015 will be 2% of energy sold to all customers by each Distribution Licensee.

Table 17- Allowed Energy Sold to Approved Street Lighting to be Recovered through proposed mechanism for year 2011

Distribution Licensee

Forecast Sales filed by Licensee (GWh)

Share of energy sold

to street lighting

Allowed share of energy sold to street lighting

Street lighting

Total (sales of DL2,3,4 excluding sales to DL5)

DL1 47.0 2,704.0 1.74% 1.74% DL2 38.0 2,769.7 1.37% 1.37% DL3 14.6 1,771.4 0.82% 0.82% DL4 20.3 1,210.5 1.68% 1.68% DL5 26.0 1,198.0 2.17% 2.00%


6.2 PROPOSED TARIFFS FOR JANUARY TO JUNE 2011

Table 18: Existing Tariffs and Proposed Tariffs for January to June 2011

Existing tariffs, announced in November 2008 Proposed tariffs, January to June 2011

Customer category and kWh (monthly)

Rate (LKR/kWh) Fixed charge (LKR/month) Fuel adj.

charge 1 Customer category and kWh (monthly)

Rate (LKR/kWh)

Fixed charge (LKR/month)

Fuel adj. charge 1

Households 2 Households 2

0-30 3.00 30 0% 0-30 3.00 30 0%

31-60 4.70 60 0% 31-60 4.70 60 0%

61-90 7.50 90 0% 61-90 8.50 90 0%

91-180 16.00 180 30% 91-120 23.50 300 0%

181-600 25.00 240 30% 121-150 28.60 300 0%

>600 30.00 240 30% 151-180 32.50 300 0%

181-240 39.00 300 0%

241-600 41.75 300 0%

>600 45.50 300 0%

Religious Religious

0-30 2.50 30 0% 0-30 2.00 30 0%

31-90 3.70 60 0% 31-90 2.80 60 0%

91-120 9.00 180 0% 91-120 6.80 180 0%

121-180 10.00 180 0% 121-180 7.50 180 0%

>180 12.50 240 0% >180 9.50 240 0%

General Purpose –GP1 15.00 240 30% General Purpose –GP1 19.50 300 0%

Government –GV1 15.00 240 30% Government –GV1 14.50 300 0%

Industrial 3 –I1 10.50 240 0% Industrial 3 –I1 11.50 300 0%

Hotel –H1 15.00 240 30% Hotel –H1 19.50 300 0%

Street Lighting 19.00 - 30% Street Lighting 17.00 - 0%

Bulk

Fixed Charge

(LKR/ month)

kVA charge

(LKR/kVA) Bulk

Fixed

Charge

(LKR/ month)

kVA Charge

(LKR/ kVA)

General Purpose –GP2 13.80 3000 750 30% General Purpose –GP2 19.70 3000 1000 0%

Government –GV2 13.80 3000 750 30% Government –GV2 13.30 3000 750 0%

Industrial – I2 Peak 9.30 3000 675 0% Industrial – I2 Peak 17.00

3000 675

0%

Off-peak 9.30 Off-peak 9.00 0%

Day 9.30 Day 12.00 0%

Hotel – H2 13.80 3000 750 30% Hotel – H2 19.70 3000 1000 0%

General Purpose –GP3 13.60 3000 675 30% General Purpose –GP3 19.35 3000 900 0%

Government –GV3 13.60 3000 675 30% Government –GV3 13.00 3000 675 0%

Industrial – I3 Peak 9.10 3000 650 0% Industrial – I3 Peak 16.50

3000 650

0%

Off-peak 9.10 Off-peak 8.70 0%

Day 9.10 Day 11.50 0%

Hotel – H3 13.60 3000 750 30% Hotel – H3 19.35 3000 900 0%

Interval (hrs)

Peak: 1830 to 2230 Off Peak: 2230 to 0530 Day: 0530 to 1830

1. Unit Charge is for the incremental monthly consumption

2. Green Tariff-premium of Rs 3.00/kwh over and above their respective unit rate would be charged from the industrial consumers who requests Green Tariff


6.3 FORM OF THE MONTHLY STATEMENT OF ACCOUNT

In accordance with the requirement to provide the customers with information on costs of generation, transmission, distribution and supply of electricity, Table 19 and Table 20 show the format proposed by the Commission. The Distribution Licensees have been requested to prepare detailed formats including this information, to be approved by the Commission.

Table 19- Proposed Form of the Monthly Statement of Account (LV Customers)

LV customerseg: Household

Rs 2,503.12

31Block 0-30 31-60 61-90 91-180 Total

Energy used (kWh) 31 31 31 33 126Rate (Rs/kWh) 3.00 7.50 7.50 18.00 Energy Charge (Rs) 93.00 232.50 232.50 594.00 1,152.00 Fixed Charge (Rs) 165.00

1,317.00

126 kWhRs/kWh Total (Rs) 8.37 1,054.11 5.09 640.72 3.22 406.34

80.00 0.61 76.34 0.13 16.15

2,273.66 (7.59) (956.66)

1,317.00 2,500.00

1,600.00

kWh Period 12,304 27-01-2011 12,480 27-02-2011 176

(100.00) 2,217.00 1,837.12

Levy on short-term debt recovery

Balance as at 27-Dec-2010

Details of Jan 2011 BillCost of electricity

Generation

Total bill for Jan 2011

TransmissionDistributionRetail services

Number of days for this bill

Account AdjustmentsTotal bill for Feb 2011Total payable as at 27-Feb -2011

Previous readingPresent readingUse for the period

Bill for Feb 2011

Total cost of electricitySurcharge or (subsidy)Total bill for Jan 2011

Levy on renewable energy

Payments 11-Jan-2011Payments 31-Jan-2011

Note: The above is only a sample and the information does not relate to any specific customer


Table 20- Proposed Form of the Monthly Statement of Account (LV bulk and MV customers)

LV bulk and MV customerseg: LV bulk customer: Industry (I2)

RsBalance as at 27-Dec-2010 250,000 Details of Jan 2011 Bill Day Peak Off peak

0530-1830 1830-2230 2230 - 0530Energy (kWh) 12,340 3,400 5,200 20,940 Rate (Rs/kWh) 12.10 15.60 8.70 Energy Charge (Rs.) 149,314 53,040 45,240 247,594 Maximum Demand ( kVA) 90Maximum Demand Charge (Rs 1000 /kVA) 90,000 Fixed Charge (Rs.) 3,000 Total bill for Jan 2011 340,594

Cost of electricity Rs/kWh or Rs/kVA

Generation Energy 7.42 Capacity 421.80

Transmission Capacity 132.59 Distribution Capacity 544.71 Retail servicesLevy on short-term debt recovery Energy 0.54 Levy on renewable energy Energy 0.11 Total cost of electricitySurcharge or (subsidy)Total bill for Jan 2011Payments 11-Jan-2010 250,000

Bill for Feb 2011 Day Peak Off-peakPrevious reading 134,300 32,670 67,980 2011Present reading 158,670 38,900 74,890 27-02-

Energy (kWh) 24,370 6,230 6,910 37,510 Maximum Demand ( kVA) 110 Account Adjustments (100)

565,182 905,676

Total charges for Feb 2011Total payable as at 27-Feb-2011

Total

49,024 500

Total (Rs)

155,375 37,962 11,933

11,293

266,087 74,507

340,594

2,389

Note: The above is only a sample and the information does not relate to any specific customer

7. CONCLUSION

The Commission proposes to implement the above tariffs from 1st January 2011, in keeping with its legal mandate to ensure that electricity is priced by Licensees at cost-reflective tariffs. The last electricity tariff increase was on 1st November 2008, which continued under the transition provisions under the Sri Lanka Electricity Act No. 20 of 2009.

At the end of this consultation process, the Commission would make a determination and the new tariffs order will be announced in December 2010, for implementation from 1st January 2011.

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Electricity Tariffs for the Period 2011-2015 in Sri Lanka

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