PUCSL Consultation Paper on 2011-2015 Tariffs

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 1

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
Distribution and Supply Licensee for CEB Distribution
DL1
Region 1
DL2
Region 2
DL3
Region 3
DL4
Region 5
DL5 Distribution and Supply Licensee LECO
FSA Fuel Supply Agreement
Licensee
CEB GL CEB Generation
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 document . The methodology has the following key features:
1

(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.

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


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
(iii) Ceylon Electricity Board in respect of Region 3 holding license number EL/D/09-005
(iv) Ceylon Electricity Board in respect of Region 4 holding license number EL/D/09-006
(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: tariff@pucsl.gov.lk


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

DL1 DL2 DL3 DL4 DL5
As filed As filed As filed As filed As filed
Year Purchases Sales Loss Purchases Sales Loss Purchases Sales Loss Purchases Sales Loss Purchases Sales Loss
(GWh) (GWh) (GWh) (GWh) (GWh) (GWh) (GWh) (GWh) (GWh) (GWh)

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%

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 Input to TL Losses filed
forecast filed by TL by TL (as a
filed by (GWh) % of input)
TL (GWh)
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
Strategies .
2

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 plan . Therefore, allowed losses of all distribution licensees
3

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
DL1
As filed Corrected
Year
Purchases Sales Sales Loss Purchases Sales Sales Allowed
(GWh) (GWh) growth (GWh) (GWh) growth 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%

DL2
As filed Corrected
Year
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


DL3
As filed Corrected
Year
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%

DL4
As filed Corrected
Year
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%

DL5
As filed Corrected
Year
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%

TL
As filed Corrected
Year
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%

Total TL and all DL networks Policy
As filed Corrected target
Sales to Sales Input to Sri Sales to Sales Input to Sri for Sri
Year
End-use growth TL's Lanka End-use growth TL's Lanka Lanka
Customers network T&D Customers network T&D T&D
(GWh) (GWh) Loss (GWh) (GWh) Loss losses
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 Revenue
Distribution Variable Revenue Cap LKR million 8,014.4 8,384.5 8,750.6 9,113.5 9,511.0
Retail Service Allowed Revenue
Retail Service Price Cap LKR/customer 428.4 428.4 428.4 428.4 428.4
Total Revenue Summary
Distribution 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 Price Cap LKR/cust 551.2 551.2 551.2 551.2 551.2
Retail Service LKR million 835.1 870.2 917.0 959.8 1,004.3









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 2015
Transmission 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 Revenue
BSOB Revenue Cap LKR million 207.0 207.0 207.0 207.0 207.0
Transmission 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

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 2015
Transmission 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 Revenue
BSOB Revenue Cap LKR million 124.6 124.6 124.6 124.6 124.6
Transmission 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

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

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 Charge
Generation 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)
LKR/MW 1,246,070
6-Month Weighed average

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 6.53
BST (E1) LKR/kWh 7.64 7.31 7.40 7.18 6.69 6.71

Interval 2 (peak)
BST (E2) LKR/kWh 10.01 9.58 9.70 9.41 8.77 8.79

Interval 3 (off-peak)
BST (E3) LKR/kWh 5.31 5.08 5.14 4.99 4.65 4.66

Renewable
Economic ST debt
energy above Total BST (E)
dispatch recovery
avoided costs
BST day (E1)
LKR/kWh 7.16 0.52 0.11 7.78
6-Month weighed average
BST peak (E2)
LKR/kWh 9.37 0.52 0.11 10.00
BST off-peak (E3)
LKR/kWh 4.97 0.52 0.11 5.60

Special Levies on BST (included in all intervals above)

Total commitment on ST debts LKR million 2800.0
for the period
Levy on NCRE purchases in LKR million 566.0
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
5,345 5,600 4,055 1,335 885 790
million)


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
2011 2012 2013 2014 2015
Licensee
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
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
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
50% of annual revenue
Total DL costs LKR million 12,942 cap
System 50% of annual revenue
costs TL LKR million 3,644 cap
Single Buyer's capacity costs LKR million 12,551 Allowed cost
Single Buyers energy costs LKR million 38,507 Allowed cost
Allowed levy, interim
Provision for Short-term debts LKR million 2800 and conditional
Levies
Allowed levy, interim
NCRE above avoided costs LKR million 566 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

Share of
Cost Share of
average
LKR each cost
cost
For a period of six months Units Value per including
excluding
kWh Govt
Govt
sold subsidies
subsidies
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%
System costs Single Buyer's allowed capacity
LKR million 12,551 2.64 13.8% 17.7%
costs
Single Buyers allowed energy costs LKR million 38,507 8.11 42.4% 54.2%
Allowed provision for Short-term
LKR million 2800 0.59 3.1% 3.9%
Levies debts
Allowed NCRE above avoided costs LKR million 566 0.12 0.6% 0.8%
Costs to be recovered through
Sub total LKR million 71,010 14.95 78.2% 100.0%
tariffs
Government Relief from long-terms debts LKR million 11,327 2.39 12.5%
Subsidies 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
49.1%
annual sales
Sales GWh 4,748
Average Cost inclusive of Govt
LKR/kWh 19.14
subsidies

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

Total
Total (Subsidy) or
Total Total Cost Forecast
revenue surcharge Cost of
Customer Category Sales (LKR revenue
(LKR on supply(LKR/kWh)
(GWh) million) (LKR/kWh)
million) customers
(LKR million)
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


PUCSL Consultation Paper on 2011-2015 Tariffs

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