6 review of bpc dgpc electricity tariff proposals

Bhutan Chamber of Commerce and Industry

REVIEW OF THE ELECTRICITY TARIFF REVISION PROPOSAL (JULY 2013 JUNE 2016) SUBMITTED BY BPC AND DGPC TO

BEA

FINAL REPORT

29 July 2013

LIST OF ABBREVIATIONS BEA - Bhutan Electricity Authority BPC - Bhutan Power Corporation Limited CoD - Cost of Debt CoE - Cost of Equity DGPC - Druk Green Power Corporation Limited DOE - Department of Energy GoI - Government of India GWh - Giga Watt Hour HV - High Voltage INR - Indian Rupee kW - Kilo Watt kWh - Kilo Watt hour kV - Kilo Volt kVA - Kilo Volt Ampere LF - Load Factor LV - Low Voltage MV - Medium Voltage MVA - Mega Volt Ampere MW - Mega Watt Nu - Ngultrum O&M - Operations and Maintenance PF - Power Factor PLF - Plant Load Factor PPA - Power Purchase Agreement RGoB - Royal Government of Bhutan RoA - Return on Asset RoE - Return on Equity TDR - Tariff Determination Regulation - 2007 WACC - Weighted Average Cost of Capital

TABLE OF CONTENTS

1. EXECUTIVE SUMMARY .................................................................................................................. 1

2. BACKGROUND ................................................................................................................................. 3

2.1 ESSENCE OF THE HYDROPOWER SECTOR IN BHUTAN ................................................ 3

2.2 ELECTRICITY USAGE IN BHUTAN ....................................................................................... 4

2.3 FINANCIAL PERFORMANCE OF DGPC AND BPC............................................................ 4

2.4 VALUE ADDITION OF THE INDUSTRIAL SECTOR TO THE ECONOMY .................... 6

2.5 HISTORICAL TARIFF RATES ................................................................................................... 9

3. INTRODUCTION ............................................................................................................................. 11

4. DGPCs TARIFF REVISION PROPOSAL ..................................................................................... 11

4.1 PARAMETERS USED IN THE DETERMINATION OF TARIFF ....................................... 11

4.1.1 WEIGHTED AVERAGE COST OF CAPITAL (WACC) ................................................... 11

4.1.2 OPERATION AND MAINTENANCE COST ..................................................................... 14

4.1.3 OPERATION AND MAINTENANCE EFFICIENCY GAINS ........................................... 15

4.1.4 REGULATORY FEES ......................................................................................................... 16

4.1.5 INFLATION ......................................................................................................................... 16

4.1.6 DEPRECIATION .................................................................................................................. 16

4.1.7 INVESTMENT PLAN .......................................................................................................... 17

4.1.8 ARREARS ............................................................................................................................ 17

4.1.9 DESIGN ENERGY ............................................................................................................... 17

4.1.10 AUXILLARY CONSUMPTION AND PLANT AVAILIBILITY .................................... 18

4.1.11 ANNUAL ENERGY GENERATION ................................................................................ 18

4.1.12 ROYALTY ENERGY ........................................................................................................ 18

4.2 FINAL TARIFF STRUCTURE ................................................................................................. 19

4.3 RECOMMENDATIONS .......................................................................................................... 20

4.4 CONCLUSION .......................................................................................................................... 22

5. BPCS TARIFF REVISION PROPOSAL ........................................................................................ 24

5.1 STRUCTURAL CHANGES IN THE TARIFF PROPOSAL ................................................. 24

5.1.1 DEMAND CHARGE BASED ON kVA RATHER THAN kW .......................................... 24

5.1.2 MINIMUM AMOUNT FOR LV CUSTOMERS ................................................................. 25

5.1.3 ELIMINATION OF CROSS SUBSIDY ............................................................................... 26

5.1.4 UPWARD REVISION OF MISCELLANEOUS CHARGES .............................................. 27

5.2 PARAMETERS USED IN THE DETERMINATION OF TARIFF ....................................... 29

5.2.1 WEIGHTED AVERAGE COST OF CAPITAL (WACC) ................................................... 29

5.2.2 OPERATION AND MAINTENANCE COST ..................................................................... 32

5.2.3 OPERATION AND MAINTENANCE EFFICIENCY GAINS ........................................... 36

5.2.4 REGULATORY FEES ......................................................................................................... 36

5.2.5 INFLATION ......................................................................................................................... 36

5.2.6 DEPRECIATION .................................................................................................................. 37

5.2.7 INVESTMENT PLAN .......................................................................................................... 38

5.2.8 ALLOCATION FACTOR .................................................................................................... 40

5.2.9 ARREARS ............................................................................................................................ 41

5.2.10 EMBEDDED GENERATION ............................................................................................ 41

5.2.11 COST OF SUPPLY ............................................................................................................ 42

5.2.12 COLLECTION RATE ........................................................................................................ 45

5.2.13 NON-TARIFF REVENUE ................................................................................................. 45

5.2.14 LOSSES .............................................................................................................................. 46

5.2.15 DEMAND CHARGES ....................................................................................................... 46

5.3 FINAL TARIFF STRUCTURE .................................................................................................. 48

5.4 TARIFF IMPACT ....................................................................................................................... 49

5.5 RECOMMENDATIONS ........................................................................................................... 51

5.6 CONCLUSION ........................................................................................................................... 55

Review of the tariff revision proposal submitted by DGPC and BPC for the tariff period 2013 to 2015

Bhutan Chamber of Commerce and Industry Page 1 of 56

1. EXECUTIVE SUMMARY

In line with the Tariff Determination Regulation (TDR) 2007, both the Bhutan Power Corporation Limited (BPC) and Druk Green Power Corporation (DGPC) have submitted a proposal to the Bhutan Electricity Authority (BEA) to revise the current electricity tariff regime for the period July 2013 to June 2016 as the current tariff period ended on 30 June 2013. The tariff period proposed by both the licensees is for a period of three years and accordingly both BPC and DGPC have proposed a tariff structure that is flat and will remain static for the entire duration of the three years without any provision for an annual increase during the tariff period. It is however recommended that as this will cause a drastic rate shock for customers when the tariff is revised, a more gradual increase be implemented wherein the tariff rates are increased at a reasonable rate annually for the duration of the three year tariff period. DGPC has submitted a tariff revision proposal to increase the current energy sale price to BPC from Nu. 1.2 per kWh to Nu. 1.99 per kWh for the additional energy quantity, which is the amount of energy drawn above the royalty energy limit. Accordingly, this will have an impact on the prices for end users of electricity in the country across all categories as BPC passes on this energy purchase price onto its customer. Similarly, BPC has made a tariff revision proposal wherein the rates across all the customer categories (LV, MV, HV and wheeling) will see an upward revision. This report reviews all aspects of the tariff revision proposal that has been submitted by both BPC and DGPC. The review conducted in this report on the proposal made by both BPC and DGPC has been done so in line with the TDR and BEAs Tariff

Review Report (September 2010). Based on the review of both the proposals, it has been found that the values assumed for many of the parameters used to determine the final tariff rates are not admissible as they are not in line with generally accepted principles or the basis that was used and approved by the BEA while reviewing the tariff proposal for the last tariff period (August 2010 to June 2013). Although, DGPC has proposed an upward revision in the generation price from Nu. 1.20/kWh to 1.99/kWh, this report recommends that the energy sale price to BPC be set at not more than Nu. 1.19/kWh for the additional energy and be free for the royalty energy. It is to be mentioned here that the tariff for the additional energy will be lower than this calculated rate as a lot of other cost figures for DGPC were not available such as the value of assets not belonging to DGPC but which have been included in the asset schedule, the quantum of allowable corporate office costs, break-up of the Operation and Maintenance costs, etc. Only with the availability of these actual costs, will it be possible to actually arrive at the final tariff rate for the additional energy. This report also does not recommend the final tariff rates for the various customer categories of BPC as a lot of information pertaining to the cost structure was not available. Furthermore, the quantum of subsidy to the various customer categories, which will be decided by the BEA and the RGoB, will determine the final tariff rates. It is also to be mentioned here that the review of BPCs tariff proposal pertains to the

first submission to BEA and not on the revised one as presented during the public hearing held on 18 July 2013.



The following table summarizes the tariff proposal submitted by BPC. Table 1 : Summary of the electricity tariff rates (current and proposed)

Customer Category Current tariff BPCs proposed subsidized tariff

% increase

Low Voltage (LV)

0-100 kWh (Nu./kWh) 0.85 1.00 17.65%

101-300 kWh (Nu./kWh) 1.62 4.10 153.09%

300+ kWh (Nu./kWh) 2.14 4.10 91.59%

LV bulk (Nu./kWh) 2.14 4.10 91.59%

Average tariff for LV 1.62 3.29 103.09%

Medium Voltage (MV)

Energy charge (Nu./kWh) 1.79 1.20 -32.96%

Demand charge (Nu./kVA/month) 115.00 856.00 644.35%

One part tariff for MV 2.16 4.30 99.07%

High Voltage (HV)

Energy charge (Nu./kWh) 1.54 1.20 -22.08%

Demand charge (Nu./kVA/month) 105.00 441.00 320.00%

One part tariff for HV 1.74 2.40 37.93%

Wheeling charges (Nu./kWh) 0.111 0.160 44.14%

Note : The current tariff for demand charge for MV and HV customers is based on kW and not on kVA

The tariff rates proposed by BPC as shown in the above table is also assuming that the additional energy and royalty energy rates payable to DGPC are maintained at the current level of Nu. 1.20/kWh and Nu. 0.13/kWh respectively. If these rates are increased, as proposed by DGPC, the end-user rates will be higher by a significant margin.



2. BACKGROUND

Before delving into the details of reviewing the tariff revision proposal as submitted by both DGPC and BPC, it is imperative to understand some major issues related to the electricity sector and the economy of Bhutan as a whole as these issues have not been considered in the formulation of the regulations determining the electricity prices in Bhutan. However, these issues are very important in the context of finalizing the end user electricity prices and need to be borne at the back of our minds while reviewing the tariff proposal. Accordingly, these issues have been highlighted in the ensuing section. 2.1 ESSENCE OF THE HYDROPOWER SECTOR IN BHUTAN

The essence of developing the hydropower sector in Bhutan way back in the early 70s with Chukha was based on the fact that it would be a way to kick-start the Bhutanese economy. Although the element of exporting the surplus electricity was also seen as an opportunity for Bhutan, this was not the principal objective of developing hydropower plants. Consequently, in all our Power Purchase Agreements (PPA) with the Government of India, it is explicitly mentioned that only the surplus electricity after meeting Bhutans domestic requirements would be

exported to India. There is no minimum energy requirement to be exported from Bhutanese hydropower plants as most PPAs are modeled on. This provision was included in all the PPAs with India so as to enable industries to come up and provide them with electricity as a first option before export. Bhutans competitive advantage on the industrial front has been relatively cheap

electricity and this has been the only reason why many power intensive industries have been set up along the southern foothills on Bhutan close to the Indian border. There is no way that our industries can compete with the cheap labour or the low transportation rates in India and the neighboring countries. These industries add a lot of value to the Bhutanese economy by way of bringing in much needed Indian Rupees/hard currency, providing jobs, paying taxes to the Government and other positive multiplier effects to the economy as a whole. The hydropower sector in Bhutan was developed with the primary aim of nurturing, developing and supporting the industrial sector in Bhutan rather than for export. The two state run monopolies currently operating in the electricity sector, DGPC and BPC, are already making huge profits and it is envisaged that they will always continue to make huge profits as the tariff determination mechanism is based on a cost-plus model wherein all the costs incurred by them are covered. Furthermore, a margin for profits is allowed after covering for all costs. The electricity tariff proposed by both the licensees is a huge jump as compared to the current rates (DGPC has proposed to increase the rates by 66% and BPC has proposed to increase the rates by 38% for HV, 99% for MV and 103% for LV customers). If the electricity tariff as proposed by both the licensees is approved, it will translate into many businesses closing shop as it will not be a viable proposition any more. Accordingly, the impact of revising the electricity tariff upwards to make only the electricity sector more profitable (although the two companies are already making



huge profit margins currently) at the cost of the industrial sector and the business community is not in line with the essence of developing the electricity sector in the first place.

2.2 ELECTRICITY USAGE IN BHUTAN A lot of research has already been conducted in the past on the positive relationship between the usage of electricity and quality of life. It is now an established fact that electricity usage leads to better/improved quality of life or standard of living. There is also a close co-relation between the quantum of electricity usage and the Human Development Index (HDI). Developed countries have a higher per capital electricity usage as compared to developing or under-developed countries. As evident, for Bhutan to improve the quality of life of its citizens, it is imperative to encourage people to use electricity to carry out many of the tasks that are currently being done using other forms of non-renewable energy. The Royal Government of Bhutan has also acknowledged this fact and has embarked on a program to ensure 100% electrification of the country by 2013. By the end of the year, Bhutan will probably be the first country in South Asia to have made such an achievement. The following table, based on data from the World Bank, shows that the per capita usage of electricity in Bhutan is way below the international average. Although, Bhutans per capita electricity usage has increased significantly in 2012 as compared to 2008, there is still much to be done on this front.

Table 2 : Per capita electricity consumption

2008 2012

World average (kWh/person) 2,858 -

Bhutan (kWh/person) 1,609 2,402

Furthermore, as per the Energy efficiency baseline study conducted by the Department of Renewable Energy, Ministry of Economic Affairs, in 2012, only 42.6% of the total energy needs of Bhutan is met through electricity while the balance (57.4%) is met through other sources of non-renewable energy. As evident it is imperative for Bhutan to promote the usage of electricity and move away from the use of non-renewables. It will be possible to make this move only if the electricity tariff is kept at an affordable level so that it is accessible to most Bhutanese. Accordingly, the tariff increase as proposed by both DGPC and BPC is not in line with the philosophy of ensuring accessibility and affordability to encourage more usage of electricity. 2.3 FINANCIAL PERFORMANCE OF DGPC AND BPC As per the TDR, both DGPC and BPC are allowed a very salubrious return on equity (12% for DGPC and 10% for BPC). With these allowed returns, both the companies made huge profit margins over the past three years of the tariff period. The following tables show the key financial indicators of BPC and DGPC for 2010, 2011 and 2012.



Table 3 : Key financial indicators of BPC for 2010, 2011 and 2012

All figures in million Nu.

2010 2011 2012 Total

Revenue 3,366.153 3,545.147 4,140.275 11,051.575

Profit after tax (PAT) 998.430 897.730 904.259 2,800.419

Net fixed assets 9,942.107 11,416.563 12,983.480 34,342.150

PAT/Net fixed assets 10.04% 7.86% 6.96% 8.15%

PAT/Revenue 29.66% 25.32% 21.84% 25.34%

Table 4 : Key financial indicators of DGPC for 2010, 2011 and 2012


2010 2011 2012 Total

Revenue 11,811.464 10,948.330 11,140.801 33,900.595

Profit after tax (PAT) 4,488.594 3,933.087 4,181.927 12,603.608

Net fixed assets 52,461.188 50,948.020 49,480.113 152,889.321

PAT/Net fixed assets 8.56% 7.72% 8.45% 8.24%

PAT/Revenue 38.00% 35.92% 37.54% 37.18%

The following table shows the consolidated profit margin (Profit after tax to total revenue) for the last three years for DGPC, BPC and other private companies in the Bhutanese economy. Table 5 : Comparison of profit margin of some companies in Bhutan

Company Consolidated profit margin for

three years (2010, 2011 and 2012)

Bhutan Power Corporation 25.34%

Druk Green Power Corporation 37.18%

Bhutan Carbide and Chemicals Limited 2.20%

Bhutan Ferro Alloys Limited 7.84%

Druk Wang Alloys 13.23%

Saint Gobain -2%

Pendent Cement Authority Limited 17.16%

Lhaki Cement 10.75%

Weighted average for 26 companies 3.20%

As can be seen from the above table, the two state-run monopolies are already outperforming other large companies operating in Bhutan currently in the context of profit margin. It should also be remembered here that the other companies besides BPC and DGPC are privately or publicly owned and operate under high business and market risk conditions. These companies are considered to be representative of the big players in the Bhutanese economy. As evident, it can be concluded that both the power sector monopolies are performing extremely well financially as the electricity tariff rates are very favorable for them. The tariff rates are favorable because the allowed CoE and other financial parameters are very high with respect to the prevailing market conditions. With the level of profits that DGPC and BPC are making, it is felt that there is actually no need for an electricity tariff revision.



With the proposed revision made by the two licensees, the financial indicators as shown above will only become better. This will however, be at the cost of the rest of the economy, wherein a lot of other industries and businesses will close shop. Based on the financial performance of the two licensees over the last three years vis--vis the other companies in Bhutan, it is felt that the allowed return and other parameters as outlined in the TDR need to be reviewed and lowered keeping in view the prevailing conditions in the Bhutanese economy. 2.4 VALUE ADDITION OF THE INDUSTRIAL SECTOR TO THE ECONOMY The general perception among the public as well as many policy makers in the Government establishment is that electricity rates are subsidized for industries in general and HV industries in particular. There is no subsidy for HV industries with regard to electricity tariff after July 2011 in line with clause 7.2.8 of the Economic Development Policy (EDP) 2010 which states that the tariff policy shall gradually remove subsidies from high voltage (HV) by 2011. Since the intention of the RGoB is to promote micro, small and medium industries, subsidies for medium voltage (MV) industrial consumers shall continue till 2020. Accordingly, the following table shows the level of subsidies that were approved for the various customer categories for the last tariff period. This is as per BEAs Tariff review report for BPC (September 2010, Clause 4.4, Table 56 on page 37 of the report). Table 6 : Subsidy approved for the various customer categories for the last tariff

period

Customer category 2010/2011 2011/2012 2012/2013 % of subsidy

LV (million Nu.) 943.878 943.878 943.878 88.50%

MV (million Nu.) 122.058 122.058 122.058 11.50%

HV (million Nu.) 93.607 - - -

Total (million Nu.) 1,159.54 1,065.94 1,065.94 100%

Accordingly, it can be seen that only 11.5% of the total quantum of the subsidy provided or Nu. 122.058 million was approved for MV customers for the last tariff period with a large proportion of subsidy being apportioned to the LV category. Most of the MV customers also pertain to hydropower projects that are currently under construction and are not necessarily MV industries. To dispel the general notion that it would be better to export electricity to India rather than sell it to HV industries in Bhutan, an analysis in terms of the revenue earned from both the options was conducted, which is summarized in the following table.

Table 7 : Analysis of revenue earning (energy sales to HV industries vs. export)

Particulars 2010 2011 2012

Number of HV industries 14 14 14

Energy sales to HV industries (GWh) 1,159.20 1,170.64 1,267.25

Revenue from energy sales to HV industries as per BPCs annual reports (million Nu.)

1,935.62 2,012.73 2,254.13

Weighted average export price to India (Nu/kWh) 1.86 1.86 1.98

Opportunity cost by not exporting to India (million Nu.)

2,156.11 2,177.39 2,509.15



Difference (revenue from HV sales and opportunity cost) (million Nu.)

220.49 164.66 255.02

Taxes paid by HV industries (million Nu.) (Only BIT/CIT)

457.13 438.31

Overall difference (revenue from HV sales and opportunity cost adjusted for taxes paid by companies) (million Nu.)

236.65 273.65

Note : Taxes paid by some companies for 2012 was not available and therefore the tax figure has not been shown.

As can be seen from the above table, it makes more financial sense to sell electricity to the HV industries in Bhutan rather than to export it to India as it earns much more revenue for the Bhutanese economy. This is also considering only Business Income Tax/Corporate Income Tax paid by these companies without taking into account other aspects such as Bhutan Sales Tax (BST) that is paid when raw materials are imported by these industries, employment that is generated, other kick-on effects it has on the economy, Personal Income Tax (PIT) paid by the employees working in these companies, etc. Furthermore, based on the data available for only nine HV industries for 2009, 2010 and 2011, the following table shows the INR earned by these industries.

Table 8 : INR earned by 9 HV industries for 2009, 2010 and 2011

Particulars Amount (million INR)

Total INR earned (sale of finished or intermediary goods)

24,300

Total INR spent (import of raw materials) 14,000

Total INR retained over three years 10,300

Total INR retained annually 3,433

It should be noted here that even if the data for 2012 is considered for the INR earnings that would have accrued from sale of the electricity to India (assuming that it was not sold to HV industries in Bhutan), INR 2,509.150 million would have been earned by the economy while the above table shows that INR 3,430 million was earned by HV industries (only 9 HV industries have been considered as opposed to 14 operating HV industries as information was available only for 9 HV industries). These 9 HV industries also provided direct jobs to over 1,674 employees (1,353 Bhutanese and 321 non-Bhutanese). As a thumb rule and based on studies conducted on labour and employment, it is an established fact that for every one direct job, a minimum of about 4 indirect jobs are created. Accordingly, based on the available data for 9 HV industries, a total of 6,765 jobs (1,353 direct and 5,412 indirect jobs) were created for Bhutanese citizens by these industries. Furthermore, based on the data available for 12 MV industries, over 1,294 jobs (880 Bhutanese and 414 non-Bhutanese) were created. Accordingly, a total of 4,400 jobs (880 direct and 3,520 indirect jobs) were created for Bhutanese citizens by these 12 MV industries. Taking into account the 9 HV and 12 MV industries, a total of 11,165 jobs (2,233 direct and 8,932 indirect jobs) were created for Bhutanese citizens by these 21 industries.



Also based on the data available for 24 industries (mix of HV and MV industries) for 2009, 2010 and 2011, the following table shows the INR earned by these industries.

Table 9 : INR earned by 24 industries (HV and MV) for 2009, 2010 and 2011

Particulars Amount (million INR)

Total INR earned (sale of finished or intermediary goods)

29,300

Total INR spent (import of raw materials) 17,500

Total INR retained over three years 11,800

Total INR retained annually 3,933

The above table shows that the 24 industries brought in a revenue of INR 3,933 million every year for 2009, 2010 and 2011. Also based on the data obtained from the Department of Revenue and Customs for 2012 for 50 industries based in the Phuentsholing region, a total of Nu. 1,190.385 million was paid by these industries to the Royal Government as duties and taxes (Nu. 539.766 million as Bhutan Sales Tax, Nu. 342.761 million as Business Income Tax/Corporate Income Tax and Nu. 307.858 million as others). As can be seen from the analysis outlined above, promoting industries is a viable option for the Bhutanese economy as it translates into more revenue, more INR earnings and more jobs being created despite the fact that a lot of other intangible benefits have not been accounted for. Quantifying these intangible benefits results in an even stronger case for promoting these industries and keeping the electricity tariff rates relatively low. With the proposed increase in the electricity tariff as made by DGPC and BPC, many industries will be forced to shut down as they will be simply unviable, given that the magnitude of increase proposed is just too much (38% for HV and 99% for MV). The detrimental impact this will have on other smaller businesses such as hotels, institutes, cottage industries, etc., is also obvious as the proposed electricity tariff increase for this category is 103%. This will also come at a time when the business environment is not too good with the liquidity crunch and the INR shortage that the Bhutanese economy is currently facing. Closure of many businesses, both small and large, as a result of the electricity tariff increase will lead to a loss in revenue for the Government in the form of taxes, loss of jobs, loss of INR earnings, etc. As a result of the loss of jobs and income for the people currently employed by these industries, a lot of other unintended social ills such as an increase in crime rates, increase in un-employment rates, etc, will be an obvious fall out. BPC and DGPCs envisaged revenue stream will also be affected negatively in the event businesses close as it will result in a situation where the energy sales target cannot be met by BPC. Although the energy can be wheeled for export, allowing BPC to make some earnings from this front, the revenue stream will be measly compared to energy sales as the wheeling charge is very small. Accordingly, BPC will not be able to recover its investments made on capacity additions and system augmentation.



2.5 HISTORICAL TARIFF RATES

If the historical trend of increase in the electricity tariff is analyzed from 1982 onwards, it can be seen that the increase in the rates was very gradual. This was done so as to avoid a sudden rate shock for customers. As can be seen from the following charts, the tariff increase as proposed by BPC is not keeping in line with the historical trend of increase for both energy as well as demand charge.

0.7 0.7 0.7 0.7 0.7

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Demand charge for MV customers (Nu/kW/month)



As can be seen from the above charts for energy charge (for both MV and HV), the energy charge was revised by about 5-10 chetrum every year in the recent past. However, as per the proposal made by BPC, the revision in energy rates would be based on a pass through mechanism wherein BPC will transfer the purchase price from DGPC to its customers. As DGPC has proposed to revise the additional energy rates to Nu. 1.99/kWh, this will be the tariff that BPC will pass on to HV and MV customers as energy charge. Similarly, the demand charge was revised by about Nu. 10/kW/month every year in the recent past. However, BPC has now proposed to revise the demand charge drastically by as much as 644% for MV customers and 340% for HV customers. Such an increase is simply unacceptable as it will lead to a severe rate shock for HV and MV customers. This is also not in line with the historical rate of increase.

0.7 0.7 0.7 0.7 0.7

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Energy charge for HV customers (Nu/kWh)

54 54 54 65 75 85 85 105 105

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Demand charge for HV customers (Nu/kW/month)



3. INTRODUCTION

This report is presented in two parts so as to address the electricity tariff revision proposals submitted by the two licensees DGPC and BPC. The first part of the report deals with the tariff revision proposal submitted by DGPC while the latter half deals with that submitted by BPC. For the purpose of reviewing the tariff revision, the Tariff Determination Regulation (TDR) 2007 as well as the principles adopted by the BEA while reviewing the tariff proposal for the last tariff period (August 2010 to June 2013) have been followed. The final tariff rates for BPC however are subject to the royalty energy and additional energy price to be charged by DGPC to BPC as well as other allowable cost structures applicable to both DGPC and BPC. The quantum of subsidy for the various customer categories, which will be decided and approved by the BEA and the RGoB will determine the royalty energy price which will in turn have a bearing on the final end user prices. 4. DGPCs TARIFF REVISION PROPOSAL

The following section reviews the tariff revision proposal submitted by DGPC and provides comments and counter revisions to their proposal complemented with justifications. 4.1 PARAMETERS USED IN THE DETERMINATION OF TARIFF The following sections explain the various parameters used in the determination of the tariff including DGPCs assumptions as well as those allowed by BEA.

4.1.1 WEIGHTED AVERAGE COST OF CAPITAL (WACC)

The Weighted Average Cost of Capital (WACC) is a parameter that is computed as a before tax parameter and is a function of the Gearing ratio, the Cost of Debt, the Cost of Equity and the tax rate. The details as to how the WACC is to be computed is outlined in section 6.6.3 of the TDR. The WACC is used for the purpose of computation of the Return on Assets, Return of Working Capital, network costs and also used as a discount factor to compute the present value of energy and costs. The WACC is computed by using the following formula

4.1.1.1 Gearing Ratio Gearing ratio is the standard ratio of debt to total fixed assets. As per the TDR, this ratio is to be determined by the Authority and the actual gearing ratio of the licensee (BPC or DGPC) is not to be used. In the determination of the tariff, DGPC has used a gearing ratio of 40%, which is in line with BEAs review for the last tariff period (August 2010 to June 2013) based on BEAs Tariff review report (Clause 2.2.3.2 on page 3 of the report).



Accordingly, for the purpose of reviewing the tariff revision proposal submitted by DGPC, a gearing ratio of 40% as proposed is accepted. 4.1.1.2 Cost of Equity (CoE) The Cost of Equity is to be determined by the Authority as per schedule C of the TDR. A Cost of Equity of 12% (post tax) has been approved in the TDR 2007 for generation, which is applicable to DGPC. In the determination of the tariff, DGPC has proposed and used a CoE of 15.5%. DGPC has justified the use of this value as the Central Electricity Regulatory Commission (CERC) allows a post tax CoE of 15.5% for generating companies based in India. However, it is not appropriate and prudent to compare the power scenario in India to that of Bhutan. The conditions prevailing in India is very different to that in Bhutan. Firstly, as evident, India is currently experiencing a huge shortage in firm as well as peak power requirement and it is imperative to attract players (both from the public and private sphere) in this sector so as to overcome the shortage. The only way to do this would be by allowing an attractive CoE such as the one being allowed currently by the CERC. Secondly, a relatively high CoE would be admissible for private sector investments as the risks associated with generation of power is relatively high at least in the Indian scenario. This is because most of the power generation in India is thermal based with coal and gas having to be imported and accordingly subject to a lot of price fluctuations based on international buying and selling rates. This is in line with the generally accepted economic principle of higher risk, higher return and lower

risk, lower return. However, in Bhutans case, allowing a high CoE for a state run monopoly with no associated market and business risks is not warranted. It is to be noted here that the two licensees are not exposed to any form of risks as the current tariff model is based on a cost-plus model and accordingly these companies will never go in the red unlike their counterparts in India. Thirdly, no equity has actually been injected by DGPC directly or for that matter even by the RGoB or DHI (DGPCs owner) for all the existing power plants being run by DGPC. The non-debt component of all the current hydropower plants which should technically have been injected as an owners equity (by DGPC or RGoB/DHI) has actually been funded through a grant by the GoI to the RGoB. According, it would not be prudent to allow such a high CoE as proposed. Although, DGPC has claimed that RGoB has passed on all the grants as equity to DHI, this is only a nominal claim and DHI has not compensated the RGoB for this passed on equity by way of a cash payout at the time of transfer. Furthermore, while reviewing the tariff revision proposal submitted by DGPC for the last tariff period (August 2010 to June 2013), BEA approved a CoE of 6% for DGPC as per BEAs Tariff review report (September 2010, Clause 2.2.3.4 on page 4 of the report). Accordingly, for the purpose of reviewing the tariff revision proposal submitted by DGPC, a cost of equity of 6% is acceptable.



4.1.1.3 Cost of Debt (CoD) The Cost of Debt (CoD) is the weighted average interest rate of DGPCs loans including any major loans that have been fully redeemed, with suitable allowance made for currency risk of any loans not made in local currency. The following table shows the status of debt of DGPC as of 31 December 2012 as per the audited financial statements for 2012.

Table 10 : Loan balance of DGPC as of 31 December 2012

Loan particulars Interest rate Loan balance 31.12.2012 (Nu.)

BHP Lower Stage 6.00% 1,319,098,352.68

BHP Upper Stage 6.00% 460,200,000.00

KHP 10.75% 1,059,857,179.24

THP 9.00% 12,420,266,369.87

CHP 5.00% -

Total

15,259,421,901.79

CoD (weighted average) 8.77%

While there is no way to verify the information on debt status provided by DGPC, these figures have been subject to auditing as per the Royal Audit Authoritys norms. Therefore, the figures as presented by DGPC have been used for the computation of CoD.

Furthermore, it has been observed that the loan balance for 2012 has been used to compute the CoD and the corresponding WACC for the entire duration of the tariff period. As evident, this approach has a fallacy as the current CoD has been used to find the WACC for the future. Accordingly, it is recommended that the loan repayment schedule be used to project the loan balance for 2013, 2014 and 2015 so as arrive at the CoD for the proposed tariff period. Accordingly, the WACC for 2013, 2014 and 2015 (calculated from the CoD for each year) should be calculated to find out the consolidated WACC for the proposed tariff period. As evident, this methodology will result in a much lower CoD for the tariff period as compared to the one proposed by DGPC. For, eg, the CoD for 2009 was 8.85% as per clause 2.2.3.3 on page 3 of the BEAs Tariff review report (September 2010) while the CoD for 2012 is 8.77%. Accordingly this will result in a much lower WACC for the tariff period as compared to DGPCs proposal. By comparing the outstanding debt in 2009 and 2012, the outstanding debt for the proposed tariff period and the consolidated CoD has been computed and is shown in the following table. However, these figures need to be verified based on the actual data to be provided by DGPC. Table 11 : DGPCs calculated outstanding debt and Cost of Debt for the proposed tariff

period (2013 to 2015)

Interest

rate Loan balance

2012 (Nu.) Loan balance

2013 (Nu.) Loan balance

2014 (Nu.)

Loan balance 2015

(Nu.)

BHP Lower Stage

6.00% 1,319,098,352 1,209,173,489 1,099,248,627 989,323,764

BHP Upper Stage

6.00% 460,200,000 424,800,000 389,400,000 354,000,000



KHP 10.75% 1,059,857,179 766,809,572 473,761,965 180,714,358

THP 9.00% 12,420,266,369 10,802,355,159 9,184,443,949 7,566,532,739

CHP 5.00% 0 0 0 0

Total 15,259,421,901 13,203,138,222 11,146,854,542 9,090,570,862

CoD (year wise) 8.77% 8.73% 8.67% 8.59%

CoD (consolidated) 8.67%

As computed in the above table, a CoD of 8.67% is more acceptable than the proposed rate of 8.77%. This value is however subject to factoring in the actual loan repayment schedule for 2013, 2014 and 2015. 4.1.1.4 Tax rate The tax rate is the prevailing rate, which DGPC has proposed as 30% in line with Section 45, Chapter 49 of the Income Tax Act of the Kingdom of Bhutan 2001. This tax rate of 30% as proposed by DGPC has been reviewed and is acceptable. 4.1.1.5 Weighted Average Cost of Capital (WACC) Based on the review of the various parameters required for the computation of WACC as discussed in the preceding sections, the following table shows the accepted values of these parameters and the corresponding value of WACC computed for the proposed tariff period.

Table 12 : Recommended parameters for WACC

Gearing ratio 40%

Cost of equity (post tax) 6%

Cost of debt 8.67%

Tax rate 30%

WACC 8.61%

However, as highlighted earlier, the actual WACC for the tariff period (2013 to 2015) will have to be verified based on the loan repayment schedules to be provided by DGPC. It is recommended that DGPC be asked to submit the status of debt for 2013, 2014 and 2015 (based on the loan repayment schedule) to compute the CoD and the WACC for each year of the tariff period. The consolidated WACC thus calculated for the tariff period has to replace the value of 8.61% that has been assumed.

4.1.2 OPERATION AND MAINTENANCE COST

An O&M allowance of Nu. 1,156 million has been proposed by DGPC in the tariff model. This is the historical O&M costs for the last three years adjusted for actual inflation rates for the past (9.1%, 8.45% and 9.54% for 2010, 2011 and 2012 respectively which is in line with the figures published by the National Statistics Bureau). This is well below the benchmark O&M cost of Nu. 1,651.50 million as prescribed by BEA in the TDR as per the Current Replacement Cost (CRC) methodology.



However, in accordance with clause 3.2.2 on page 14 of the BEAs Tariff review report (September 2010), which was used for the approval of DGPCs tariff revision for the last tariff period (August 2010 to June 2013), BEA did not allow costs related to royalty energy payments, donations & community welfare expenses, income from rent & hire charges, insurance costs & corporate office expenses to be included in the O&M costs of DGPC for the last tariff period. These costs need to be deducted from the overall O&M costs incurred by DGPC for 2010 to 2012 while computing the average O&M costs to be used as a benchmark cost. After analyzing DGPCs annual financial statements for 2010 and 2011, the following deductible costs were ascertained. It is to be noted here that the detailed break-up of the costs in the Schedules of the financial statements for 2012 were not available for review.

Table 13 : Actual O&M costs incurred by DGPC for 2010, 2011 and 2012

Actual O&M expenses 2010 2011 2012

Employee cost 530.58 608.14 677.39

O&M cost 302.93 369.41 333.53

Administration and other expenses 126.38 115.47 136.27

Total 959.890 1,093.020 1,147.190

Average O&M costs 1,066.700

Deductions to be made

Donations 11.812 16.195 15.598

Community welfare expenses 4.758

Other income 14.105 13.807 13.660

Insurance - - -

Regulatory fees - - -

Total deductions 30.675 30.002 29.258

Final O&M expenses after adjustment 929.215 1,063.018 1,117.932

Average O&M costs after adjustment 1,036.722

However, as most of the expenses were not available as can be seen from the above table, the computed average O&M expenses (for data that was available) has been used for the purpose of reviewing the tariff. Accordingly, an average O&M allowance of Nu. 1,123.404 million (Nu. 1,036.722 million adjusted for actual inflation rates for the past) has been assumed for the purpose of determining the tariff. However, it is recommended that the detailed breakup of O&M costs be made available by DGPC for the purpose of enabling the deduction of inadmissible costs from the average O&M benchmark costs. 4.1.3 OPERATION AND MAINTENANCE EFFICIENCY GAINS

As per clause 6.3.2 of the TDR, an O&M efficiency gain is to the used for the purpose of determining the tariff rates. As per the BEAs approval for the last tariff period

(August 2010 to June 2013) based on BEAs Tariff review report (September 2010,

clause 3.2.2.7 on page 17), an O&M efficiency gain of 2% was approved and used. As per DGPCs tariff revision proposal, an efficiency gain of 0% has been used for

determining the tariff rates. However, for the purpose of reviewing the tariff revision proposal submitted by DGPC, an O&M efficiency gain of 2% has been used.



4.1.4 REGULATORY FEES

DGPC has not proposed for any regulatory fees for the tariff period as it has already been included in the O&M costs. However, as it was not possible to ascertain this, it is felt that this cost needs to be removed from the O&M costs and booked separately for the purpose of transparency. It is recommended that the regulatory fees paid be made available by DGPC for the purpose of deducting them from the average O&M benchmark costs and booking this separately. As per the Regulatory Fees Regulation 2006, a regulatory fee of 0.15% of revenues is to be paid by DGPC annually. 4.1.5 INFLATION

Inflation is used for the purpose of estimating the following three parameters in the tariff determination model (i) O&M expenses for the subsequent years of the tariff period based on a

benchmark for the base year of 2012 (ii) Inventories for the subsequent years of the tariff period based on a benchmark for the base year of 2012 (iii) Cost escalation in the Capital expenditure Accordingly, DGPC has used an average inflation figure of 9.03% based on the historical inflation figures for the past (2010 to 2012) as published by the National Statistics Bureau.

Table 14 : Actual inflation rates for 2010, 2011 and 2012 as per the NSB

2010 2011 2012 Average

Inflation (%) 9.10% 8.45% 9.54% 9.03%

However, it was felt that a more realistic figure should be used based on the forecast made by the International Monetary Fund (IMF). Accordingly, the following figures have been used for the purpose of reviewing the tariff proposal.

Table 15 : Proposed inflation rates for 2013, 2014 and 2015 as per IMF forecasts

2013 2014 2015 Average

Inflation (%) 7.81% 6.45% 6.45% 6.9%

4.1.6 DEPRECIATION

The depreciation rates have been calculated based on the prescribed useful service life of the various assets classes and gross & net asset values as per the investment schedule planned during the tariff period (2013 to 2016). Accordingly, the annual deprecation amounts have been computed and reviewed based on the proposed capital investments, existing gross asset base and the allowed depreciation rates as per the useful service life of the asset prescribed in the TDR.



4.1.7 INVESTMENT PLAN

In line with the gross value of assets approved for the last tariff period (August 2010 to June 2013) based on BEAs Tariff review report (September 2010, clause 3.1.2 on

page 8), some asset classes which are not owned directly by DGPC have to be deducted from DGPCs declared gross asset value for 2012 for the purpose of estimating the depreciation value and the return of assets for the proposed tariff period, which have a bearing on the final tariff rates. In 2009, the gross value of these assets was Nu. 1,263.64 million. Accordingly, based on the type of assets included in this amount, the depreciation based on the life of the assets has to be computed to find out the net value of these assets in 2013, 2014 and 2015. Furthermore, the following table shows the asset capitalization schedule of DGPC for the last tariff period (2010 to 2012). As evident, DGPC was able to meet only 59% of its proposed asset capitalization figures and accordingly, this factor needs to be incorporated while approving the asset capitalization schedule for the proposed tariff period. Table 16 : DGPCs asset capitalization schedule (proposed, approved and actual for the last tariff period)


2010 2011 2012 Total

Proposed capitalization 1,039.10 1,132.04 1,653.96 3,825.10

Approved capitalization 639.70 577.77 945.50 2,162.97

Actual capitalization 779.70 678.89 798.93 2,257.52

% variation (proposed vs. actual)

-24.96% -40.03% -51.70% -40.98%

DGPC has proposed to capitalize Nu. 2,926.190 million worth of assets in 2013, 2014 and 2015. However keeping in view the past historical trend, it is proposed that only 59% or Nu. 1,726.45 million worth of assets be considered for capitalization for the proposed tariff period. It is also proposed that since it is very difficult or next to impossible to come up with the exact figures for the quantum of assets that will be capitalized over the next three years, a figure based on historical trend be assumed for the purpose of arriving at the tariff rates. However, this can be adjusted in the next tariff period once the actual capitalization figures are available for the past period. 4.1.8 ARREARS

For the purpose of computing the return on working capital, the arrears in days is required. Accordingly, DGPC has proposed an arrear of 57 days which is in line with the arrears as approved for the last tariff period (August 2010 to June 2013) based on BEAs Tariff review report (September 2010, Table 26 on page 19). This parameter, as proposed, is acceptable. 4.1.9 DESIGN ENERGY

The design energy is defined in the TDR as the total energy generated in a 90% dependable year with 95% installed capacity of the station.



The design energy as proposed by DGPC is based on 85% of the average actual annual generation of 6,934.5 GWh of energy that has been achieved from 2003 to 2012. Only 85% of this has been proposed so as to account and adjust for the royalty energy volume. However this is not in line with the TDR - 2007 as well as the approval for the last tariff period (August 2010 to June 2013) based on BEAs Tariff review report (September 2010, clause 3.4.2 on page 22). The design energy that has been assumed for the purpose of this review is as per the design energy that was approved by the BEA for the last tariff period. Furthermore, 93 GWh of energy from Tsibjalumchhu diversion scheme in Chukha has been added from 2015 onwards to the approved values of design energy for the last tariff period. The following table shows the design energy that has been reviewed and considered for the purpose of determining the tariff rates.

Table 17 : Recommended design energy volume for the proposed tariff period

2013 2014 2015

Design energy (GWh) 6,387.120 6,387.120 6,480.120

4.1.10 AUXILLARY CONSUMPTION AND PLANT AVAILIBILITY

DGPC has proposed an auxiliary consumption of 1.2% and power plant availability of 98% as allowed by the BEA (schedule D of the TDR) although DGPCs actual data for the past three years is 1.28% and 97.66% for auxiliary consumption and power plant availability respectively. The values as proposed by DGPC are accepted. 4.1.11 ANNUAL ENERGY GENERATION

The annual energy generation that has been assumed for the purpose of determining the tariff rates has been obtained from the annual design energy after adjusting it for auxiliary consumption of 1.2% and plant availability of 98%. The following table shows the expected annual energy volume that has been considered to calculate the tariff for the additional energy.

Table 18 : Recommended annual energy volume for the proposed tariff period

2013 2014 2015

Design energy (GWh) 6,387.120 6,387.120 6,480.120

Annual energy volume after accounting for auxiliary consumption and plant availability (GWh)

6,184.265 6,184.265 6,274.311

4.1.12 ROYALTY ENERGY

DGPC has proposed a royalty energy proportion of 15% of average annual energy forecast after adjusting for auxiliary consumption. This is in line with the methodology approved for the last tariff period (August 2010 to June 2013) based on BEAs Tariff Review Report (September 2010, Clause 4.1.1 page 23). Accordingly, this proposal is acceptable. The following table shows the quantum of royalty energy that has been considered for the tariff period.



Table 19 : Recommended royalty energy volume for the proposed tariff period

2013 2014 2015

Energy generation forecast (GWh) 6,863.110 6,894.110 6,956.110

Royalty energy volume after accounting for auxiliary consumption (GWh)

1,017.113 1,021.707 1,030.896

4.2 FINAL TARIFF STRUCTURE Based on the parameters that have been proposed by DGPC for the purpose of computing the tariff, a generation tariff of Nu. 1.99/kWh for the additional energy amount has been proposed by DGPC for the period July 2013 to June 2015. However, based on the review carried out on the various parameters that were assumed by DGPC for the purpose of determining the tariff, the recommended rate for the additional energy has been computed as Nu. 1.19/kWh. Accordingly, this means that the final approved rate for the additional energy should not exceed this computed value as a lot of other cost structures which need to be deleted have not been done so due to lack of proper information. The following tables shows the cost structure and the values used in the determination of the final additional energy rate.

Table 20 : Maximum total cost of supply for the proposed tariff period

2013 2014 2015

Operation and Maintenance (million Nu.) 1,182.890 1,252.939 1,323.703

Depreciation (million Nu.) 2,301.845 2,341.626 2,380.762

Return on Assets (million Nu.) 3,784.596 3,633.823 3,493.779

Return on Working Capital (million Nu.) 143.757 146.381 149.369

Total Cost (million Nu.) 7,413.087 7,374.769 7,347.614

Table 21 : Maximum average cost of supply for additional energy

2013 2014 2015

Discounted Total Cost (million Nu.) 6,825.365 13,077.119 18,812.029

Discounted Energy (GWh) 5,693.966 10,936.504 15,833.687

Average additional energy cost (Nu/kWh) 1.19

The rate for the royalty energy depends on the quantum of subsidy that is determined and approved by the RGoB. However, it is recommended that the royalty energy rate be kept at free or Nu. 0.0/kWh in line with clause 7.2.9 of the Economic Development Policy 2010 (EDP) which states that Recognizing hydropower as a national resource, it shall be provided at affordable rates to reduce non-renewable energy use. The generating companies shall provide 15% of the total power generation as free royalty energy from medium, large and mega power generating companies to the Royal Government. Accordingly, based on this clause of the EDP, the quantum of subsidy required to be provided is as shown in the following table.



Table 22 : Average cost of supply for royalty energy

2013 2014 2015

Discounted Subsidy amount (million Nu.) 1,116.271 2,148.676 3,107.765

Discounted Royalty energy (GWh) 936.474 1,802.598 2,607.226

Average Royalty Price 0.00 Nu/kWh

4.3 RECOMMENDATIONS While reviewing the tariff revision proposal made by DGPC, the following issues were encountered which would require to be looked at in greater detail and needs to be addressed in a holistic manner (i) The current methodology being used by BEA for determining the generation

tariff is based on a cost-plus model applicable for a short time duration (3 years). As evident, DGPCs plants have been constructed with about 60-70% of debt made available by the Government of India/Austria. The loan repayment schedule is for 12 years or more after which time the debt is redeemed leading to a drastic reduction in the cost of debt, the WACC and accordingly the tariff. As the life of the plant is assumed to be for about 35 years (as per CERC regulations), this current tariff determination methodology will result in very high tariffs for the initial 12 years or so of the plant life with a drastic drop in the rates after the loans are redeemed. Accordingly, such a methodology leads to a very wide variation in prices over the plant life. It is recommended that a pricing methodology similar to the one adopted for determining the tariff for export of power to India (done inter-governmentally between the GoI and the RGoB) be adopted at least for generation licensees. Such a revised methodology will also provide end users and investors a clear price path (short, medium and long term) in terms of the generation prices (and accordingly the end user prices) so as to enable them to make prudent investment decisions. In the current model, investors are uncertain of the electricity prices in the middle and long term.

(ii) It is recommended that the loan repayment schedule be used to project the

loan balance for 2013, 2014 and 2015 so as arrive at the CoD for the proposed tariff period. Accordingly, the WACC for 2013, 2014 and 2015 (calculated from the CoD for each year) should be calculated to find out the consolidated WACC for the proposed tariff period. It is recommended that DGPC be asked to submit the status of debt for 2013, 2014 and 2015 (based on the loan repayment schedule) to compute the CoD and the WACC for each year of the proposed tariff period.

(iii) As per the review done by BEA on the tariff proposal submitted by DGPC

for the last tariff (August 2010 to June 2013), certain costs related to royalty energy payments, donations & community welfare expenses, income from rent & hire charges, insurance costs & corporate office expenses were excluded from the overall actual O&M costs incurred by DGPC. Accordingly, these costs also need to be deducted from the overall O&M costs incurred by DGPC for 2010 to 2012 while computing the average O&M costs to be used as a benchmark cost for the proposed tariff period. However, as most of these expenses were not available, it is recommended that these costs be made available by DGPC for the purpose of deducting them from the average O&M benchmark costs.



(iv) It is recommended that the regulatory fees paid be made available by DGPC for the purpose of deducting them from the average O&M benchmark costs and booking this separately (without factoring for inflation as done if clubbed with O&M costs).

(v) It is recommended that DGPCs assets be reviewed more closely as some

asset classes which are not owned directly by DGPC have to be deducted from DGPCs declared gross asset value for 2012 for the purpose of

estimating the depreciation value and the return on assets for the proposed tariff period, which have a bearing on the final tariff rates. Furthermore, as DGPC has not been able to meet its proposed asset capitalization figures for the last tariff period (proposed vs. realized), an appropriate asset performance factor needs to be incorporated while approving the asset capitalization schedule for the proposed tariff period. It is recommended that the historic trend be used for this purpose with appropriate adjustments made in the next tariff period.

(vi) It is recommended that a more transparent and open model be developed

for the purpose of determining the quantum of subsidy to be allocated to the various customer categories so as to determine the royalty energy rates. As of now, it is determined by the Minister of the Ministry of Economic Affairs as per the Electricity Act but nonetheless it is felt that a more robust methodology be developed so that everyone is aware of the basis for the application of the subsidy amount.

(vii) The current generation price determination model does not take into

consideration the export energy prices and the quantum of energy that is exported. These parameters have a big impact on the revenue streams for the DGPC (and thereby the price that DGPC can charge to BPC) and will also have a bearing on the quantum of subsidy that can be provided to the various customer categories. As evident, the generation price for the quantum of energy that is exported is also taken into account in the current model while determining the tariff for the additional energy but the benefits that accrue from the proceeds of the export sales do not feature in the same model. In effect what this means is that the cost to generate the export energy is being paid by domestic customers but the benefits arising from the export sales are not given to domestic customers, which is not fair and transparent. Incorporation of these parameters into the tariff determination model needs to be looked into so as to build a more robust, acceptable and transparent model.

(viii) The benchmark value for estimating the allowable O&M expenses using the

Current Replacement Cost (CRC) methodology as prescribed in the TDR needs to be reviewed and revised. It seems in-appropriate to have double standards in the application of the methodology as outlined in the TDR (use of certain criteria only when it suits the requirement).

(ix) With the current model between the Royal Government of Bhutan and the

Government of India on the revision of the energy sale price to India (increase by 10% every 5 years until the loan repayment schedule and an increase by 5% every 5 years after the loan is redeemed), the revenue streams will increase steadily for DGPC whenever the export tariff is increased. For 2012, the overall CoE for DGPC was already 10.88% and with



the revision of the export tariff for Tala and Kurichhu scheduled for December 2016 (and four other plants which are currently under construction coming online), this will increase even further. This will mean that there will come a time when the CoE will exceed the allowable 12% as outlined in the TDR. Accordingly, it is felt that this needs to be considered while approving the tariff in the initial years itself so that DGPC does not exceed the allowable CoE over the life of the generating plants.

(x) The allowable CoE of 12% for DGPC as per Schedule C of the TDR seems to

be too high keeping in view the corresponding returns that most companies in Bhutan are currently making. It also needs to be borne in mind that these companies are operating in a risky environment as they are exposed to market and business risks. They also operate in a competitive and free market environment while DGPC is a monopoly and is not subjected to any risks as the tariff mechanism is a cost plus model allowing DGPC to recover all costs and make a profit margin also. Allowing such a high CoE to DGPC translates into a high tariff rate charged by BPC also resulting in many industries being unviable. Accordingly, making a lot of other companies unviable for the benefit of one company does not seem to be a good option for the economy. It is recommended that the allowable CoE for DGPC be reviewed and lowered to a more reasonable and acceptable figure.

4.4 CONCLUSION The review conducted in this report on the proposal made by DGPC has been done so in line with the TDR and BEAs Tariff Review Report (September 2010). Based on

the review of the proposal made by DGPC to revise the generation tariff, it has been found that the values assumed for many of the parameters used to determine the final tariff rates are not admissible as they are not in line with generally accepted principles or the basis that was used and approved by the BEA while reviewing the tariff proposal for the last tariff period (August 2010 to June 2013). The following table shows the various parameters used for determining the tariff rates that were reviewed and revised. Table 23 : Summary of parameters assumed by DGPC and recommended values

Parameter Proposed by DGPC Reviewed and recommended

Gearing ratio (%) 40% 40%

Cost of Debt (%) 8.77% 8.67%

Cost of Equity (%) 15.5% 6%

Benchmark O& M values (%) 1.5% 1.5%

Benchmark O&M values (absolute amount in million Nu.)

Nu. 1,156 million Nu. 1,123.404

million (maximum)

O&M efficiency gain (%) 0% 2%

Inflation (%) 9.03% 6.9%

Asset performance factor - 59% of proposed

value

Design energy (GWh) 85% of average actual

generation

As per the values approved for the last

tariff period



Based on the review carried out on the proposal submitted by DGPC to BEA, the recommended rate for the additional energy has been computed as not more than Nu. 1.19/kWh while the rate for the royalty energy is recommended to be passed on to BPC on a free basis.



5. BPCS TARIFF REVISION PROPOSAL

The following section covers the tariff revision proposal as submitted by BPC as well as comments and counter revisions to their proposal along with justifications. 5.1 STRUCTURAL CHANGES IN THE TARIFF PROPOSAL As compared to the tariff structure that is currently in place or was in the past, the tariff revision proposal that has been made by BPC has some major changes and digresses in some key aspects. The following four major changes have been proposed in this context - (i) Demand charge for MV and HV customers to be based on apparent power (kVA or MVA) rather than on active power (kW or MW) (ii) Minimum bill amount for LV customers using less than 100 kWh of energy per month (iii) Elimination of cross subsidy extended by specific customer categories to others (iv) Upward revision of miscellaneous charges Each of these proposed changes are elaborated in greater detail in the ensuing section.

5.1.1 DEMAND CHARGE BASED ON kVA RATHER THAN kW

Up until the current tariff revision proposal, the demand charge for MV and HV customers has been based on the amount of active power (kW or MW) drawn by a customer in a month. Accordingly, this billing structure does not have any incentive for users to become efficient by means of improving on the power factor. However, BPC has always required customers to maintain a minimum power factor of 85% as outlined in clause 20 of the Terms and Conditions of supply of electricity for MV and HV customers of BPC. From experience, this has been very difficult to maintain and monitor both for BPC as well as for its customers. Consequently, the proposed change in the tariff structure will inherently incentivize customers to become more efficient in the utilization of electricity by means of improving the power factor. This can be achieved by use of better equipment, use of capacitor banks and ensuring regular & proper operation and maintenance of electrical equipment at the customers premises. Such a tariff mechanism will also institute a system wherein customers using electricity efficiently will be rewarded while inefficient users will be penalized by means of having to pay more for the usage of electricity. It is however yet to be seen how HV and MV customers will actually benefit from moving into this immediately. A very strong case needs to be made by BPC so as to convince HV and MV customers of the positive impacts of such a new system. HV and MV customers will have to make a lot of investments so as to actually see the benefits of the new system. The proposal as put up by BPC also does not provide adequate time for HV and MV customers to plan and make investments so as to enhance efficiency. The change or



increase in the demand charge should have been gradual and staggered as it will not be possible for HV and MV customers to make changes in their usage pattern, change of equipment or installation of new equipment immediately but it would take them at least about a year or two to do this. It would also be desirable if BPC works very closely with the industry fraternity in terms of hand-holding and knowledge transfer to help improve efficiency. This could be done by conducting training programs at the factory premises, carrying out advocacy and awareness programs, conducting case studies on some industries, etc. After the industries are convinced and ready to move to the new billing system for demand charges, BPC can then enforce this proposed change. 5.1.2 MINIMUM AMOUNT FOR LV CUSTOMERS

BPC has proposed that for LV customers, even if the customers monthly electricity usage is less than 100 kWh, the customer will be charged for the entire 100 kWh. However, if the monthly usage is greater than 100 kWh, the customer shall be charged for the actual amount of electricity used. The justification provided by BPC for adopting this change is to encourage effective utilization of scarce resources and to recover part of the fixed asset costs of rural electrification built for uplifting socio-economic conditions of the economically disadvantaged. However, it should be noted that if this proposal is adopted, it is going to be counter-productive and will have a detrimental impact in terms of cost of living for poor households and will disproportionately affect those in the lower income bracket. People who use less than 100 kWh of electricity per month are already among the most economically disadvantaged and a lifeline block with the least tariff rate currently exists precisely for the benefit of this group of customers. The monthly electricity consumption of an economically disadvantaged user is estimated to be about 73 kWh per month (see table below). Table 24 : Estimated monthly consumption of electricity of an economically

disadvantaged user

Electrical appliance Quantity Wattage Hours of

usage per day

Total energy used per day

(kWh)

Light bulb 2 60 4 0.48

Heater 0 2000 6 0

Geyser 0 2000 2 0

TV 0 300 4 0

Boiler 0 650 3 0

Rice cooker 1 650 3 1.95

Curry cooker 0 650 3 0

Refrigerator 0 400 24 0

Daily energy usage

2.43

Monthly energy usage 72.90



Based on this estimate, the monthly increase in the users electricity bill with the proposed change (billing a minimum of 100 kWh of electricity irrespective of the fact that less than this is actually used) would increase drastically from 18% to 61% compared to his/her current monthly electricity bill as shown in the following table. Table 25 : Estimated monthly increase in electricity bill for an economically

disadvantaged user

Tariff (Nu./kWh) Monthly bill (Nu.)

Low Voltage block

Existing Proposed Existing

Tariff

Proposed Tariff w/out minimum

bill amount

Proposed Tariff with minimum

bill amount

0-100 kWh 0.85 1.00 61.97 72.90 100.00

101-300 kWh 1.62 4.10 - - -

300+ kWh 2.14 4.10 - - -

Total 61.97 72.90 100.00

Increase (in Nu.) 10.94 38.03

Increase (in %) 18% 61%

The justification provided by BPC that the proposed change will lead to more effective utilization of scarce resources is not warranted because such a user will be unable to afford other appliances to increase his/her electricity consumption as the cost becomes prohibitive. This is a well-established fact from the numerous amount of research that has already been conducted in the past with respect to rural electrification projects. Most beneficiaries in the rural areas already face problems in terms of paying for the cost of internal house electrification alone after a rural electrification activity is completed in a village, let alone purchasing an additional appliance such as a curry cooker or a water boiler. The counter-productive nature of this proposal lies in the real possibility that instead of leading to energy conservation, users will keep their lights on unnecessarily as there will be no incentive for them to switch them off given that they would pay the same amount leading up to the 100 kWh threshold. Adopting this proposal would be highly unfair to the customer and especially to those in the low-income bracket. It will prove to be counter-productive to the very essence of its goal and lead to more wastage of scarce resources rather than promotion of effective utilization. 5.1.3 ELIMINATION OF CROSS SUBSIDY

BPC has proposed that for the computation of the tariff structure for the various customer categories, separate Weighted Average Cost of Capital (WACC) be used for the different customer categories rather than a consolidated WACC. This is a deviation from the provisions of the TDR (Section 6.6.3) wherein a consolidated WACC is to be used for the determination of the tariff structure for each customer category rather than use of separate WACCs for various customer categories. The WACC for the various customer categories can be obtained from the Cost of Debt (CoD) which is different for various customer categories based on apportioning the existing amount of debt to the various customer categories based on the asset



allocation factor as approved for the last tariff period (August 2010 to June 2013) based on BEAs Tariff review report (September 2010, Table 54 on page 36). As proposed by BPC, the Cost of Debt for the various customer categories and the calculated WACC is shown below:

Table 26 : Calculated WACC for the various customer categories

Consolidated Export HV MV LV

Gearing ratio 44% 44% 44% 44% 44%

Cost of equity (post tax) 16% 16% 16% 16% 16%

Cost of debt 2.76% 9.43% 10.73% 1.38% 1.27%

Tax rate 30% 30% 30% 30% 30%

WACC 14.01% 16.95% 17.52% 13.41% 13.36%

Based on the WACC computed for the various customer categories as shown in the above table, the tariff for the various customer categories has been calculated and is shown in the following table. Table 27 : Tariff structure calculated based on a consolidated WACC and

individual WACC for each category (based on BPCs proposal)

Customer category

Unit Tariff structure based on

a consolidated WACC

Tariff structure based on separate WACC for various

customer categories

Export Nu/kWh 0.143 0.160

HV Nu/kWh 2.26 2.40

MV Nu/kWh 4.36 4.29

LV Nu/kWh 3.40 3.29

The above tariff rates have been computed based on the tariff parameters used by BPC and will be different if parameters as allowed by BEA are used. Furthermore, the tariff rates shown above have been computed based on the assumption that all of the subsidies have been apportioned only to the LV customer category, as proposed by BPC. However, the table above is shown only to illustrate the impact of using separate WACCs for different customer categories on the corresponding tariff structure. It can therefore be concluded that if a consolidated WACC is used for the computation of the tariff for the various customer categories, the LV and MV customer categories subsidize the HV and export category leading to higher tariff rates for the LV and MV group. As proposed by BPC, this methodology is acceptable as the cost structure for each customer category is more transparent and in line with section 7 of the TDR which states that subsidy policies will be implemented only as determined by

6 review of bpc dgpc electricity tariff proposals

Documents

maintenance cost

determination of tariff

bhutan chamber of commerce

watt kwh

dgpcs tariff revision

watt hour kv

debt coe cost

historical tariff rates