DGPC Tariff Review Report 2013

Bhutan Electricity Authority

Druk Green Power Corporation Limited

Tariff Review Report

October 2013

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Contents Executive Summary ................................................................................................................................ ii

1 Background ..................................................................................................................................... 1

2 Regulatory parameters ..................................................................................................................... 1

2.1 Tariff period ............................................................................................................................ 1

2.2 WACC Parameters .................................................................................................................. 2

2.3 Inflation ................................................................................................................................... 8

2.4 Other regulatory parameters .................................................................................................... 9

3 Allowances, Cost of Supply and Energy Volumes ......................................................................... 9

3.1 Allowances for depreciations (DEP) and return on fixed assets (RoA) ................................ 10

3.2 O&M allowances ................................................................................................................... 18

3.3 RoWC allowances ................................................................................................................. 23

3.4 Energy Volumes .................................................................................................................... 24

4 Tariff determination ...................................................................................................................... 26

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Executive Summary

The Druk Green Power Corporation Limited (DGPC) proposed the revision of the generation

tariff from Nu. 1.2/kWh to Nu. 1.99/kWh. The DGPCs tariff application has been reviewed and the allowed pre-tax Weighted Average Cost of Capital is determined as 11.96 %, based

on a 10 % after-tax cost of equity, a 8.48 % cost of debt, and a 40 % gearing ratio.

The cost allowances have been set according to the provisions of the Tariff Determination

Regulation. The DGPCs investments during the tariff period, is largely driven by new investments in the construction of buildings and installation and up-gradation of power house

facilities.

The design energy was calculated using the definition of the design energy in the Tariff

Determination Regulation. Considering the approved regulatory parameters and the cost

allowances, the generation tariff for DGPC for the tariff period 2013/14 to 2015/16 was set to

Nu. 1.39/kWh.

The annual average royalty energy volume of 1,049 GWh was approved by the Lhengye

Zhuntshog which is 15% of the forecasted generation of Chukha, Kurichhu, Basochhu and

Tala hydropower plants adjusted for auxiliary consumption.

Based on the approved annual average royalty energy volume of 1,049 GWh valued at the

generation tariff of Nu. 1.39/kWh, the total subsidy available worked out to Nu. 1,458 million

per year. This annual subsidy of Nu 1,458 million was allocated to Low Voltage and Medium

Voltage Customers for the period 2013/2014 to 2015/16. Based on the decision of the

Lhengye Zhungtshog to derive the full value of the royalty energy for allocation of subsidy to

the LV and MV customers, the BEA determined the royalty energy price to be zero for the

tariff period 1st October 2013 to 30

th June 2016.

1

1 Background

The Druk Green Power Corporation Limited (DGPC) submitted their proposal for revision of

domestic generation tariffs vide letter no. 42/DGPC/MD/BEA/2013/54 dated 9th

April 2013.

The DGPC submitted that increase in the domestic generation tariffs has become necessary

due to the following reasons:

The generation tariff hasnt been revised since 2007.

To reflect the actual cost of power generation in keeping with the Tariff Determination Regulations (TDR) as well as norms that are applicable to other utilities in the region.

The Bhutan Electricity Authority (BEA) not only consider a generation tariff based on norms consistent with the TDR but further consider incorporating some norms from

other utilities in the region.

Subsidies considered for domestic consumers could be passed on by the Government through appropriate pricing of the royalty energy or other mechanisms rather than

incorporating in the generation tariffs.

Provide a steady revenue stream to the Royal Government of Bhutan (RGoB) from the hydropower sector and spur further growth in this very important sector.

Considering the new business environment, some changes in the TDR for the 2013 generation tariff review are necessary if the hydropower sector is to sustain future

maintenance and replacement requirements.

As per the Tariff Determination Regulation (TDR), Licensees are required to submit their

tariff proposals by 1st March 2010; however the DGPC delayed the submission of their tariff

proposal due to non finalization of the tariff proposals. The final DGPC tariff proposal was

submitted on 9th

April 2013.

The DGPC proposed to increase the Additional Price from the current level of 1.20 Nu/kWh

to 1.99 Nu/kWh.

2 Regulatory parameters

2.1 Tariff period

The length of the tariff period is not regulated in the TDR and is therefore to be determined as

part of the tariff review.

The DGPC tariff proposed a three year tariff period as in the previous tariff period. The 2012

audited financial statements have been used as a reference for the calculations.

The BEAs view is that a three year tariff period is reasonable considering the prevailing uncertainties regarding the development of the electricity sector in Bhutan in the next few

years. The tariff period is the same as proposed by the Bhutan Power Corporation Limited

(BPC), which is necessary to avoid a new review of BPCs tariffs in the middle of a tariff period. Therefore, the BEA has approved a two years and nine months tariff period, starting

from 1st October 2013 to 30

th June 2016.

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2.2 WACC Parameters

The WACC shall be calculated as the before-tax Weighted Average Cost of Capital in

accordance with section 6.6.3 in the TDR:

GearingCoDTax

GearingCoEWACC

)1(

)1(

Where,

WACC is the Weighted Average Cost of Capital, as a percentage;

CoE is the Cost of Equity, as a percentage; as determined by the Authority for the Licensee;

Gearing is the standard ratio of debt to total fixed assets, as determined by the Authority,

CoD is the Cost of Debt, as a percentage, being the weighted average interest rate of the Licensees loans with suitable allowance made for currency risk of any loans not made in local currency, provided that the cost of debt should not exceed reasonable

benchmarks;

Tax is the prevailing rate of company taxation, as a percentage.

2.2.1 DGPC proposal

The DGPC has proposed a WACC of 16.79%, based on a gearing of 40%, CoE of 15.5%

CoD of 8.77% and a tax rate of 30%. The DGPC has also calculated the WACC according to

a gearing ratio of 40% and CoE of 12% as determined in the TDR Schedule C. The resulting

WACC is 13.79%, which has not been proposed.

The DGPC justify its proposal by referring to the CERC norms for regulated Indian power

companies which it think gives a good basis considering the integrated nature of Bhutans power sector to the Indian power market. The CERC norms prescribe a COE of 15.5%.

Further the DGPC state that the expected return for the electricity sector in India as per the

CAPM1 model works out to over 16% by applying the Beta of 0.912 of the National Hydro

Power Corporation Ltd (NHPC), interest rates of ten years Indian Government bonds of 8.3%,

and the average Indian market return since 1991 of 17.4% on the capital asset pricing model.

The DGPCs view is that since the rate determined by the market is based on the risk assessment of the investment, the returns for power sector in Bhutan should also be

comparable or higher to that of the electricity sector in India. The DGPC also shows that

many of the companies listed at the Royal Securities Exchange of Bhutan have had much

higher average return on equity in the last 5 years than the CoE for DGPC.

1 Capital Asset Pricing Model (CAPM) is widely used to determine expected return on equity 2 Source: http://in.reuters.com/finance/stocks/overview?symbol=NHPC.NS 3 Source: http://www.bloomberg.com/quote/GIND10YR:IND

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2.2.2 Inputs from stakeholders

During the public hearing, some customers expressed that the cost of equity of 15.5% for a

company owned by the government and built with grants and soft financing is too high and

that the BEA should consider using the CoE of 6% as in the previous tariff period. They also

expressed that, it is not appropriate and prudent to compare the power scenario in India to that

of Bhutan as DGPC is not exposed to any form of risks since the current tariff model is based

on a cost-plus model.

They also submitted that no equity has actually been injected by DGPC directly or by the

RGoB or DHI. 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.

2.2.3 BEA review

The WACC parameters are determined in the TDR Schedule C, but may be updated by the

BEA from time to time in accordance with Section 1.8 of the TDR. The parameters are

discussed in the subsections below.

2.2.3.1 Tax

The BEA has verified that the proposed tax rate is in accordance with the rate prescribed in

the Income Tax Act of the Kingdom of Bhutan 2001. The BEA has found no reasons to

amend the proposed tax rate.

2.2.3.2 Gearing

The DGPC proposed a gearing ratio of 40%, as approved by BEA in the Schedule C of TDR.

The TDR does not prescribe any specific allowances for return on equity, but an allowance

for return on assets. The allowance for return on assets is determined as the WACC multiplied

with the DGPCs net asset value at the beginning of any tariff year. The gearing ratio, cost of debt, cost of equity and tax rate are regulatory parameters which are necessary to determine

the WACC. If the actual gearing ratio is different from the one in the TDR, the expected

return on equity will be different from the cost of equity parameter in the regulation.

It is BEAs opinion that the WACC, under normal circumstances, should reflect an optimal gearing ratio and not the actual gearing of the licensee. A gearing ratio of 70% is used in

many countries, e.g. in India. The WACC is not supposed to reflect a companys true costs of capital unless the gearing is optimal. The owners may inject more equity than the regulated

gearing ratio prescribes, but cannot expect a higher return on this excess equity than the Cost

of Debt.

However, the hydropower sector in Bhutan has been developed with huge amounts of grants

to the Royal Government of Bhutan and only around 40 % of the investments are financed

through loans as shown in Table 1.

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Table 1 DGPCs financing structure

Loan particulars (mil Nu) BHP CHP KHP THP Total

Total Project Cost(mil Nu) 3,261 2,465 5,600 41,258 52,594

RGoB contribution(mil Nu) 329

Grant (mil Nu) 586 1,479 3,360 24,755 30,180

Loan (mil Nu) 2,346 986 2,240 16,503 22,075

Debt Equity ratio (%) 72:28 40:60 40:60 40:60 42:58

However, given the fact that the current plants could not be financed by a sufficiently higher

gearing ratio than 40%, the BEA has decided to maintain the gearing ratio in the TDR

Schedule C. The gearing ratio is expected to increase in the future when new plants are

commissioned, as the grants for new projects are expected to be less than before. The gearing

ratio will therefore be reconsidered during the next tariff review.

2.2.3.3 Cost of Debt

The DGPC proposed Cost of Debt (CoD) is 8.77% which is calculated as the weighted

average of the interest rate on their loans by the end of 2012, using the loan balance at

31.12.2012 as weights as shown in Table 2.

Table 2 DGPCs proposed cost of debt

Loan particulars Year of loan

disbursement

Principle

Amount

(mill. Nu.)

Interest

rate

Repayment

period

Balance

31.12.2012

(mill. Nu.)

BHP Lower Stage 02.04.2002 17.06.2005 1, 649 6.00% 15 1,319

BHP Upper Stage 30.12.1997 14.10.2007 708 6.00% 20 460

KHP 18.09.1997 28.03.2003 2, 240 10.75% 12 1,060

THP 31.03.1997 31.12.2006 15, 589 9.00% 12 12,420

CHP 984 5.00% 15 0

Totals / weighted average interest rate 21, 170 8.77% 15,259

The BEA has verified the principle loan amount, interest rate, repayment period and the loan

balance as of 31.12.2012 and found that loan balance of THP includes Nu 4,822 million and

loan balance of KHP includes Nu. 500 million stemming from IDC. Since IDC is capitalized

and DGPC doesnt pay interest on the IDC, the IDC is deducted from the loan balance.

The BEA found that the proposed approach of estimating the CoD as the weighted average

interest of current loans using the loan balance at the end of 2012-2014 as weights to be

appropriate and calculated the Cost of Debt as given below. Based on the above, the BEA has

calculated the CoD as 8.48 %.

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Table 3 DGPCs current cost of debt

Loan

particulars

Year of loan

disbursement

Principle

Amount

(mil. Nu.)

Interest

rate

Balance

31.12.2012

(mil. Nu.)

Balance

31.12.2013

(mil. Nu.)

Balance

31.12.2014

(mil. Nu.)

BHP (Lower) 02.04.2002 17.06.2005 1, 649 6.00% 1,319 1,209 1,099

BHP(Upper) 30.12.1997 14.10.2007 708 6.00% 460 425 389

KHP 18.09.1997 28.03.2003 2, 240 10.75% 560 373 187

THP 31.03.1997 31.12.2006 15, 589 9.00% 7,598 6,332 5,065

Totals / 21, 170 9,937 8,339 6,741

weighted average interest rate 8.56% 8.49% 8.39%

Cost of Debt 8.48%

2.2.3.4 Cost of Equity

DGPC has applied for a CoE of 15.5 %, referring to the CERC norms for Cost of Equity

(CoE) in the Indian power sector. In India the regulated CoE is 15.5 %, plus 0.5 % if the

investment project is commissioned according to the plan. The DGPCs view is that the CoE of the power sector in Bhutan should be equal to or higher than the CoE of the Indian power

sector, considering the integrated nature of the two sectors. The BEA viewed that despite the

close links between India and Bhutan, the CoE for the two sectors are not directly comparable

mainly due to differences in gearing ratios and the investors perspective.

The CoE can be estimated in many ways, but the Capital Asset Pricing Model (CAPM) is

widely used. According to the CAPM model the CoE should be estimated as:

= + (1)

is the Equity Risk Premium, which normally is measured as the extra return that stocks have to offer relative to Government bonds to compensate for the higher risk of investing in

stocks. is the risk free rate, and normally is the return on the Government bond the ERP is measured against. The is the only sector specific variable in the formula, and is a measure of the systematic risk for the sector compared to the risk of a balanced portfolio on the stock

market. The higher risk compared to the stock market, the higher .

The is normally estimated based on the correlation between a companys or sectors return and the return on a balanced stock market portfolio. If the return of the company correlates

perfectly with the market portfolio, is 1. If the return of the company is more volatile than the return on the market portfolio is higher than 1, and if it is less volatile then it is less than 1. If there is no correlation between the companys return and the return on the market

portfolio, is 0. If there is a negative correlation, is less than 0, and this implies that the companys return will increase if the return on the stock market decreases. The is not a measure of the total risk of investing in only the specific company or sector, but a measure of

the risk that the investor cannot remove through diversification of his investment in a well

balanced portfolio. Traditionally the is much lower for the power sector than other sectors listed on the stock exchange, due to the low covariance between return on assets between the

power sector and the market portfolio. This is also the reason for why investments in the

power sector are attractive to investors despite the lower return on assets. The investor can

reduce its risk by adding power sector investments to its portfolio.

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is the levered beta, which take the capital structure (gearing) of the company into account. If two companies with the same systematic risk (represented by the unlevered beta, ) have different gearing, they will have different . The transformation from the unlevered beta to the levered beta, taking the Debt/Equity- ratio (D/E) into account, is by most practitioners

done according to the following formula:

= 1 +

(2)

Whether the CERC CoE norm of 15.5 % is relevant in Bhutan or not is depending on whether

the risk free rate, the equity risk premium and levered beta is the same or not. If all parameters

are the same in both countries, the answer is yes. It any of the parameters are different, the

answer is most likely no. Whether it should be higher or lower will depend on the differences

in the factors.

If investors in Bhutan have access to the same Government bonds and stock markets as Indian

investors, we can assume that the risk free rate and the equity risk premium is the same in

both countries. However, the BEA viewed that the equity risk premium should be lower due

to differences in the investors perspective between India and Bhutan. DHI as an investor will most likely have limitations in its investment possibilities compared to an Indian private

international investor. Due to such limitations, the BEA viewed that the ERP should be lower

for DHI than for Indian investors. Regarding the levered beta, the BEA viewed that there

should be differences due to different gearing ratios. The differences in gearing between

Indian and Bhutanese companies will give differences in , and therefore also in the CoE.

To exemplify the view of the BEA have calculated the differences assuming that a CoE of

15.5 % is a reasonable level in India, and that the underlying factors in the CoE formula is

relevant for the power sector in Bhutan, the CoE can be recalculated to a level suitable for

Bhutan if one know two out of the three parameters in formula (2).

In an article on the CoE in India from June 2010, it is argued that the CoE for Indian investors

should be 15.5 %4, the same as the CERC norm. The article is written by Saurabh Mukherjea,

Head of Equities, Institutional Equities, Ambit Capital. He assumed the risk free rate to be 7.4

% (expected return on 10-year Government bond), the levered beta to be 1.1, and the ERP to

be 7.25 %. From formula (2) we get:

= 7.4% + 1.1 7.25% 15.5% (3)

Since he assumed to be 1.1, and we know that the CERC gearing norm is 70% debt and 30% equity, we can apply formula (2) to calculate the .

=

1+ =

1.1

1+0.7 0.3 = . 33 (4)

DGPC has a gearing of around 40 percent. By applying formula (2) on , which we for this calculation assume to be the same in India and Bhutan, we get a for the DGPC like:

= 0.33 1 +0.4

0.6 = 0.56 (5)

By replacing the of 1.1 (India) with 0.56 (Bhutan), we get the following CoE for Bhutan:

4 http://www.vccircle.com/byinvitation/2010/06/14/what-real-cost-equity-india

7

= 7.4% + 0.56 7.25% 11.5% (6)

Currently the return on 10-year Government bonds is less than 7.3 %5. This will reduce the

CoE slightly. So, under the assumptions in Mukherejas calculations the Indian CoE adjusted for the DGPCs gearing ratio is 11.5 %, which is could be a benchmark used in the tariff

review. However, the BEA viewed that both the and the ERP assumptions are too high in Mukherejas example.

One of the few sources for assessing the CoE using CAPM on the power sector of India is

Professor of finance Aswath Damodaran at the Stern School of Business at the New York

University. He is an authority in corporate finance and equity evaluation, has done many

studies of equities throughout the world. Also in the Indian power sector. Much of his work

and data is available at his website6.

Professor Damodaran calculates CoE in USD, with the return on as 10-year US Government

bond as a risk free rate of return. His updated figures for 2013 regarding the CoE estimation

for the Indian power sector are:

Risk free rate: 1.76 % (10 year US Government bond)

ERP: 8.8 percent, based on an ERP of 5.8 % for mature markets and a country risk premium for India of 3 %.

Unlevered beta, : 0.4657, estimated for the Indian power sector.

Adjusting the unlevered beta to a levered beta at 40 % gearing, using formula (4), gives a of 0.7762. Inserting these figures into formula (2) we get:

() = 1.76% + 0.7762 8.8% 8.6% (7)

However, this CoE is in USD. To transform the CoE into other currencies, Professor

Damodaran suggests adjusting the CoE with the difference between the inflation in that

currency and the USD. The difference in inflation between India and US has been

approximately 4.7 % the last 10 years, but the 2009 and 2010 figures were quite extreme. The

average difference in the inflation forecast for the next 3 years is around 3 %7. Adjusting the

result in (7) for expected differences in the inflation, we get an estimated CoE for Bhutan of

11.6 %. The BEA viewed that also the and ERP used by was too high for Bhutan.

The DGPC has shown the average return on equity of several companies listed at Royal

Securities Exchange of Bhutan is higher than the one of DGPC. The BEA viewed that it is not

relevant to compare the CoE applied on DGPC setting their average cost of supply with those

listed companies. The main reason is that the average return on equity is based on a too short

times series, and that the gearing ratios probably is quite different from DGPCs.

The BEA viewed that the best estimate could be obtained using the CAPM model on the

updated data of Professor Damodaran, adjusting the and the ERP, and applying the differences in the expected inflation between the US and India. None of the figures are

accurate, but the BEA viewed that the should be in the interval 0.3 0.4, the ERP in the interval 7.2% 8.8% and the inflation in the interval 3% - 4%. The reason for adjusting the

was that DGPCs PPAs with India reduces the systematic risk significantly. The systematic risk is the risk that the investor cannot reduce through diversification of his investment

5 http://www.tradingeconomics.com/india/government-bond-yield 6 http://pages.stern.nyu.edu/~adamodar/ 7 www.tradingeconomics.com

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portfolio. If a recession occurs in India and Bhutan, the return of DGPC will not decline as

much as the return of balanced portfolio of shares from companies listed at the stock

exchange. The reason is that a recession will reduce the demand for all goods and services in

both India and Bhutan, and hence also the demand for power. However, the PPAs ensure that

the DGPC will sell the same amount of energy as before the recession. Since domestic

demand decreases, the export increases. Since the export price is higher than the domestic

price, the return on assets in DGPC will increase. Therefore, investments in DGPC equity

should be very attractive for investors. They will decrease the systematic risk of the investor.

Regarding the ERP, DHI is an investor with limitations in its investment portfolio compared

to a private international investor. Such limitations will result in an expected return on

investments that is lower than the one assumed by professor Damodaran. It is quite common

to assume that Governments in general should expect a lesser return on assets than investors

on stock exchange, though there might be examples of the opposite.

The BEA has found it difficult to estimate the differences in inflation between the US and

India exactly. Based on the historic differences it should be more than 4 %. Based on the

current expectations it should be less than 3%. BEA expects it to be between 3 and 4 %.

Based on the expected intervals of the , the ERP and the inflation the BEA viewed that a CoE of 10 % should be appropriate for investors in DGPC equity.

2.2.3.5 The WACC

Given the tax rate of 30% and the CoD of 8.48 %, the level of the WACC is dependent on the

CoE and Gearing ratio. The BEA has decided to update the CoE to 10% in the TDR Schedule

C (Generation), update the Gearing ratio to 40%-70% in order to provide a signal to the

Licensees to move towards a gearing ratio of 70% and approved a WACC of 11.96 % for the

DGPC as shown in Table 4.

Table 4 The proposed and approved WACC

DGPC BEA

Gearing: 40 % 40%

CoE: 15.5 % 10%

CoD: 8.77% 8.48%

Tax: 30 % 30%

WACC: 16.79% 11.96%

2.3 Inflation

The historical inflation rates are used for calculation of historical costs in 2012 values, which

is the base year for this tariff review. The forecasted inflation rate is used for the calculation

of the forecasted costs (allowances) in each of the years in the tariff period.

The DGPC has used the historical inflation figures for 2010, 2011 and 2012 from the

Quarterly Consumer Price Index Bulletin of the National Statistics Bureau as shown in Table

5 when inflating historical data to 2012 prices.

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Table 5 Historical inflation rates

Inflation 2010 2011 2012 Average

Q4 9.1% 8.45% 9.54% 9.03%

The DGPC proposed an average inflation rate of 9.03% which is the average annual inflation

rate for the 4th

Quarter of the past three years since forecasts for anticipated inflation rates are

not available.

The BEA has verified that the proposed historical inflation rates for the years of 2010 until

2012 and found that the average historical inflation rate for the period 2010-2012 was 8.9 %

which is calculated as the arithmetic average of the quarterly inflation rates published by

National Statistics Bureau.

The BEA has checked that the World Economic Outlook International Monetary Fund (IMF)

inflation forecast for the period 2013 to 2016.

Table 6 IMF Inflation forecasts

Year IMF

2013 9.33%

2014 8.16%

2015 7.68%

2016 6.57%

2013/14-2015/16 7.94%

Source: http://world-economic-outlook.findthedata.org/l/629/Bhutan

The BEA finds that taking an arithmetic average of the three relevant years is an appropriate

approach when forecasting the average inflation rate for this tariff period.

The BEA has approved average historical inflation rate of 8.9% and the forecasted inflation

rate of 7.94 % to be used in this tariff review.

2.4 Other regulatory parameters

The O&M benchmark and O&M efficiency gain parameters are discussed in Section 3.2. Any

other amendments to the regulatory parameters has not been proposed by the DGPC and

therefore not discussed in this review report.

3 Allowances, Cost of Supply and Energy Volumes

The total cost of supply for the DGPC in any tariff year shall be determined in accordance to

the TDR Section 8.1.1,

RoWCRoADEPOMTC

Where

TC is the total cost of supply in million Ngultrum;

OM is the allowance for operating and maintenance costs in million Ngultrum, including any regulatory and other fees;

DEP is the allowance for depreciation of assets in million Ngultrum;

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RoA is the return on fixed assets in million Ngultrum, determined as

NAWACCRoA , where

o WACC is the weighted average cost of capital, as determined in accordance with the TDR Section 6.6

o NA is the net value of all fixed assets at the start of the year, in million Ngultrum

RoWC is the return on working capital in million Ngultrum

3.1 Allowances for depreciations (DEP) and return on fixed assets (RoA)

As per Section 6.4 of the TDR, asset values is to be based on historical asset values and

Licensees are allowed to include the Interest During Construction (IDC) and associated labour

costs to be capitalized. The regulation also allows the allowance for asset additions and asset

disposals and other asset value adjustments over the course of the tariff period.

The allowance for depreciation is based on the economic lifetime of the assets, in accordance

with Schedule B of the regulation, which may be updated by the BEA from time to time. The

allowance for depreciation allows taking asset additions and removals over the tariff period

into consideration. The return on assets is to be determined as the product of the WACC and

the net asset values.

3.1.1 DGPC proposal

3.1.1.1 Assets schedule at the end of 2012

The DGPCs gross asset value was taken from the audited financial statement for 2012. DGPC submitted that BEAs depreciation of assets as given in Schedule B of the TDR are different from depreciation rates normally used for accounting purposes. Therefore, the asset

schedule was worked out using the BEAs depreciation rates and used for tariff calculation. The DGPC submitted the asset schedule as shown in Table 7 and

Table 8.

Table 7 DGPCs proposed asset schedule at the end of 2012

Fixed assets (Nu. mill.) Gross value Acc. Dep. Net value Depreciation

Land 150.36 0.00 150.36 0.00

Buildings 2454.17 534.34 1919.82 81.81

Civil structures 2869.24 1214.26 1654.98 95.64

Dam complex 11,747.10 3321.26 8425.84 391.57

Water conductor 23,546.69 5823.86 17722.84 784.89

Power house 18,904.45 4762.10 14142.35 725.83

Transmission equipment 680.92 178.00 502.92 22.70

Equipment 746.69 494.64 252.06 98.63

Office equipment 359.99 158.87 174.12 68.25

Total 61,459.63 16,514.33 44,945.30 2,269.32

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Table 8 Plant wise asset schedule at the end of 2012

Fixed assets (Nu. mill.) Gross value Acc. Dep Net value Depreciation

Corporate Office 248.51 66.14 182.36 28.85

BHP 3951.92 1148.46 2802.65 142.23

CHP 3746.83 2194.53 1552.30 173.89

KHP 6116.88 2291.35 3825.53 205.65

THP 47,396.28 10,813.83 36,582.45 1637.40

Total 61,460.42 16,514.31 44,945.29 2,188.02

DGPC has calculated the depreciation and accumulated depreciation based on the gross asset

value and the asset capitalization date of all the individual assets existing as of 31st

December

2012 in the book of accounts. DGPC applied the BEAs depreciation rates to these individual assets according to their aging to calculate the depreciation, accumulated depreciation, and the

net asset values using BEAs depreciation rates.

DGPC submits that the net asset value in the annual accounts schedule is higher than the asset

values calculated for tariff determination since the depreciation rate of 3.33 % for Civil

Structures is allowed by the TDR compared to 3% allowed as per the accounting policy of

DGPC and Civil Structures comprises of about 73.4% of the total assets of DGPC. Therefore,

DGPC submits that the tariff would actually be higher if calculated using the asset values

from DGPC annual accounts.

DGPC submits that in 2008, Druk Green was established to bring about synergy and

efficiency by amalgamating all the existing power plants under one management instead of

having four separate managements and company structures. It was also submitted that the

Corporate Office has now assumed the complete cost of the management of the power plants,

which earlier had separate management structures.

DGPC submits that it has no other mandate but to develop, operate and maintain hydropower

plants, therefore, it is only rational that the entire cost including the assets and investments of

the Corporate Office be taken into consideration in the tariff determination model. Further,

DGPC submits that during the course of the project implementation and thereafter during the

operation and maintenance stages, some assets such as schools, hospitals, roads and other

infrastructure are created at the cost of the project for the use of project as well as of the

community in case such facilities do not exist in the project areas and are not provided by the

Government but sometimes transferred to relevant Government agencies after the project

completion. However, DGPC submits that the projects continue to reflect the costs in their

books and service the liabilities. Since some of these costs were however not allowed in the

2010 tariff review, DGPC proposed that these costs should be re-incorporated back in the

generation tariff review.

3.1.1.2 Investments Asset additions 2013 - 2016

The investment schedule was submitted by the DGPC is as per the DGPCs investment plan. The investment plan includes the investments of the existing four generation plants and the

Corporate Office. All major hydropower projects financed by the Government of India as part

12

of the 10,000 MW by the year 2020 projects and the investments envisaged for the other Druk

Green projects such as the Nikachhu are not included in this schedule. The investment

schedule is prepared as per year of capitalization. The DGPC proposed investment plan for

2013-2016 is as given in Table 9 and

Table 10.

Table 9 DGPCs proposed investment schedule

Fixed assets (Nu. mill.) 2013 2014 2015 2016

Land - - - -

Buildings 180.09 250.00 401.00 124.00

Civil structures - - 11.00 65.00

Dam complex 57.66 268.08 20.00 -

Water conductor - - - -

Power house 92.06 676.95 488.20 500.45

Transmission equipment 2.60 18.00 5.00 -

Equipment 53.50 40.00 - -


Total 501.54 1,365.83 1,058.82 816.25

Table 10 Plant wise investment schedule as proposed by DGPC

Capital expenditures

(Nu. mill.) 2013 2014 2015 2016


BHP 35.20 21.63 75.73 68.56

CHP 123.26 231.39 353.11 184.82

KHP 104.16 165.02 122.87 18.77

THP 220.78 928.74 167.10 421.10

Total 501.54 1,365.83 1,058.82 816.25

3.1.1.3 Proposed return on assets and depreciations

The proposed return on asset is calculated as the product of the proposed WACC (16.79%)

and the calculated net asset value at the end of each year. The depreciations are calculated in

Table 11 as per the depreciation rates in Schedule B in the TDR.

Table 11 DGPCs proposed allowances for return on assets and depreciations

RoA and DEP (Nu. mill) 2013 2014 2015 2016

Gross asset values 61,961 63,327 64,386 65,202

Accumulated depreciations 18,808 21,163 23,592 26,080

Net asset value 43,153 42,164 40,794 39,122

Return on Asset (RoA) 7,397.8 7,164.2 6,966.2 6,710.8

Depreciation (DEP) 2,294 2,355 2,428 2,488

13

3.1.2 BEA review

3.1.2.1 Asset schedule at the end of 2012

The DGPCs proposal is based on gross asset values as per audited accounts 2012 and the depreciation, accumulated depreciation, and the net asset values using BEAs depreciation rates. The BEAs depreciation rates were applied to these individual assets according to their aging to calculate the depreciation, accumulated depreciation, and the net asset values using

BEAs depreciation rates.

Table 12 DGPC proposed and Plant wise asset schedule at the end of 2012

Fixed assets (Nu. mill.) Gross value Acc. Dep Net value Depreciation


BHP 3,951.12 1,148.46 2,802.65 142.30

CHP 3,746.83 2,194.53 1,552.30 173.89

KHP 6,116.88 2,291.35 3,825.53 205.65

THP 47,396.28 10,813.84 36,582.45 1,637.40

Plant wise Total 61,459.63 16,514.33 44,945.30 2,188.09

DGPC proposal 61,459.63 16,514.33 44,945.30 2,269.32

There is some difference in the total annual depreciation shown in Table 7: DGPCs proposed

asset schedule at the end of 2012 and Table 8: Plant wise asset schedule at the end of 2012. The

depreciation in DGPC proposed asset schedule is higher due to 1) use of depreciation rate of 20%

for Power House (Generator runners) 2) CO - depreciation rate for Telephone Exchange missed

and used a rate of 10% instead of 20% for Other Equipments. 3) BHP - depreciation rate for

Telephone Exchange missed. 4) CHP - depreciation rates for telephone exchange and Boat

missed. 5) KHP - depreciation rates for Telephone Exchange and Boat missed and used 10%

instead of 20% for Other Equipments. 6) THP- missed depreciation rates for loose tools, Boat and

Vehicle and used 10% instead of 20% for other Equipments.

Considering the above, the DGPCs proposed asset schedule at the end of 2012 as provided in Table 7 was used.

The BEA also found that by using the BEA depreciation rates, DGPCs net asset value decreased by Nu. 4,534.81 million as also submitted by DGPC.

Table 13 Difference in net asset value due to depreciation rates

(Nu. mill.) Gross value Acc. Dep Net value Depreciation

Using DGPC dep rates 61,459.63 11,979.51 49,480.11 2,284.97

Using BEA dep rates 61,459.63 16,514.33 44,945.30 2,269.32

Difference 4,534.81

During the last tariff review, BEA had deducted Nu. 1,263.64 million worth of assets which

have been handed over to various agencies.

14

The DGPC submitted that assets which have been handed over to other agencies were not

removed from DGPC Schedule A since the assets that were handed to other agencies were

created during the project construction phase. DGPC submits that these facilities that were

handed over were used as project office, residential quarters, guest houses, stores, workshops

etc. which were mandatorily required to create all the generating assets. During the project

construction phase, to facilitate the timely implementation of the project, the project offices

had to be located in the vicinity of communication (road, communication) facility. These

facilities were utilised by the project from 1997 till 2010. The cost of these structures had

been apportioned to the major capital works such as Dam, Head Race Tunnel, and Power

House and other civil works and do not appear as a separate class of asset. The cost had to be

apportioned as these structures were transferred free of cost. Therefore, it was proposed to be

allowed to be recovered since DGPC continues to service the liabilities.

In 2010, DGPC had included assets listed in Table 14 in their asset schedule.

Table 14 Assets which are not owned by DGPC, but included in their books of accounts

Name of the Agencies Cost as per

the THPA

report

(Mill. Nu.)

Cost with IDC

(Mill. Nu.)

Cost with IDC

and Dep

(Mil Nu.)

Gaeddu College of Business Studies 933.41 1,094.89 1,097.88

Gedu Middle Secondary School 61.36 71.97 72.17

Bhutan Telecom 7.61 8.93 8.95

Royal Bhutan Police 5.62 6.60 6.61

Gedu Hospital 69.27 81.25 81.42

Total 1,077.27 1,263.64 1,267.03

Since BEA viewed that, only assets that are owned and used by the DGPC can be included in

the tariff allowances, the above listed assets were deducted from DGPCs asset schedule. The DGPC has confirmed that there are no such assets besides the ones listed above which have

been handed over to other agencies.

In order to get the correct net asset values and depreciations for the allowances, the gross asset

value was reduced by Nu. 1,264 million and the depreciation was reduced by Nu. 147.84

million, which is equal to the total annual and accumulated depreciations for the THP

building.

The Corporate Offices (CO) net asset values of Nu.182.36 million and depreciations of Nu 28.85 million has been allocated to BHP, CHP, KHP and THP and are therefore included in

the DGPCs proposed RoA and DEP allowances. It was found that Nu. 32 million worth of land for the Gelephu Hydropower Service Center has been included in the Corporate Office

asset schedule. Since the costs of the maintenance of the current plants are covered by the

O&M allowance, cost of the land for the service center should be deducted from the

Corporate Office assets.

Further the CO assets are not directly linked to any specific plant or project, therefore, BEA

has decided to allocate only one third of these net asset values and depreciations to the

existing plants and two third to other projects.

15

Considering the above, the BEA has decided to use recalculated asset schedule using BEAs depreciation rates submitted by DGPC in Table 7 and corrected by BEA in Table 15 for the

tariff calculations.

Table 15 - BEAs reviewed Asset schedule per 31.12.2012 (Nu. mill.)

Fixed assets (Nu. mill.) Gross value Acc. Dep. Net value Depreciation

Land 118.00 - 118.00 0

Buildings 1,189.48 384.45 805.03 39.65

Civil structures 2,869.15 1,214.17 1,654.98 95.64

Dam complex 11,747.10 3,321.26 8,425.84 391.57

Water conductor 23,546.69 5,823.86 17,722.84 784.89

Power house 18,904.45 4,762.10 14,142.35 725.83

Transmission equipment 680.87 177.99 502.88 22.70

Equipment 727.53 483.93 243.60 95.87


Total 60,054.08 16,322.40 43,731.69 2,206.99

3.1.2.2 Investments Asset additions 2010 - 2013

The DGPCs investment schedule for the year 2013-2016 had been based on capitalized

investments per the year of capitalization. Since net asset value from the beginning of the

tariff year will be used for the calculation of the tariffs, DGPC was asked to resubmit the

investment schedule by deducting the investments which are capitalized after July 2015.

DGPC has submitted that assets capitalized after 2016 are not considered, however, the since

the tariff is determined for three years, the period from 2013 to 2015 should be considered on

full year basis and that if BEA determines the tariff on July-June basis, assets for 2016 should

be considered.

The investment schedule as per the year of capitalization has been calculated as shown in

Table 16.

Table 16 Investment schedule as per year of capitalization

Project/Activity 2013 2014 2015 2016

Land - - - -

Buildings 180.09 250.00 401.00 124.00

Civil Structures - - 11.00 65.00

Dam Complex - 57.66 268.08 20.00

Water Conductor - - - -

Power House 92.06 676.95 488.20 500.45

Transmission Equipment 2.60 18.00 5.00 -

Equipment 53.50 40.00 - -

Office Equipment 115.63 112.80 133.62 126.80

Total 501.54 1,365.83 1,058.82 816.25

16

The BEA reviewed the DGPCs proposed investment plan and found that the following projects, with a total investment cost of Nu. 880 million proposed for the period 2013-2016,

were also included in the investment plan for the tariff period 2010-2013.

Table 17 Investments approved in 2010 Tariff Review

Project/Activity Project

Cost 2013-

2016

BEA

Approved

2010

Capitalized

amount

(Nu. Mil)

CO Druk Green Corporate Office Building

320.00

57.80

0.04

BHP Upgradation of SCADA System for both

Plants and Switchyard.

115.00

25.50

-

CHP Replacement of present Radial Gate Hoisting

mechanism with Hydraulic system.

162.50

170.13

-

KHP Permanent Residential Quarters 46 Units to

replace temporary Sheds, Guest House & Recreation

Centre and other common facilities.

53.35

105.06

60.96

KHP Upgrading present protection and operating

system to SCADA platform

200.00

110.00 -

THP Power House Access Road Stabilization and

realignment with option for tunnel or at least 6 km of

new road

30.00

80.00 -

Total 880.85 548.49 61.00

The BEA reviewed the implementation of the 2010 approved planned investments and found

that DGPC had over spent/ under spent the BEA tariff review 2010 amounts for the Corporate

Office and Plant investments as shown in Table 18. However, DGPC on the whole had

achieved 98% of the investment approved in 2010 tariff review.

Table 18 Plant wise investments approved in 2010 Tariff Review

Project/Activity BEA tariff

review 2010

Capitalized

amount as of

April 2013

% of BEA

tariff review

2010

Corporate Office 134.91 139.17 103%

BHP 157.73 332.99 211%

CHP 898.34 393.31 44%

KHP 218.85 182.05 83%

THP 987.37 1,309.93 133%

Total 2397.20 2357.46 98%

The low completion rate for CHP and KHP projects was mainly due to the postponement,

cancellation and delay in the execution of the projects detailed in Table 19 and Table 20.

Table 19 CHP Investments approved in 2010 Tariff Review

Sl.

No

Project/Activity BEA Approved

Plan 2010

( Nu. Mil)

Status

1. Store and Workshop 25.500 postponed

2. Construction of RBA Quarters at Wangkha 237.150 cancelled

3. Construction of Office Building 4.760 postponed

17

4. Radial Gates Upgradation to Hydraulic

system for four gates 170.130

postponed

5. Civil,-HRT inspection, TRT modification 52.700

TRT modification work

cancelled.

6. Automation of control and protection system 170.000 postponed

7. HV Lines - 11 kv re routing 21.250 postponed

Construction of Residential Quarters 46

Units 105.06

Total 786.55

Table 20 KHP Investments approved in 2010 Tariff Review

Sl.

No

Project/Activity BEA Approved Plan 2010 ( Nu. Mil) Status

1 Construction of Residential

Quarters 46 units 105.06

57% capitalized,

rest postponed

2 Stores and workshop 25.50 Cancelled

Total 130.56

The following investments shall be deducted from the investment plans for 2013-2016 for the

tariff calculations.

CO P/Ling land development consultancy Nu. 2 million (2013), since the investment is not necessary for operating or maintaining the existing plants and is also

covered by Other O&M expenses: consultancy charges.

CO Construction of P/Ling Regional Office and Transit Stores and Residential Units Nu. 100.00 million (2014-2016), since the investment is not necessary for operating or maintaining the existing plants;

CHP, BHP and THP Purchase of spare runners Nu. 337 million considering spare parts are included in the inventory allowances and average service life of the runners

at CHP and BHP.

From the other Corporate Office investment plans (vehicles, Office Equipment, Data Processing Equipment, Furniture & Fixtures, Loose Tools, Security Equipment etc.)

worth Nu. 78.20 million and Nu. 320 million for construction of DGPC Corporate

Office building, two third of these investments is removed from the tariff calculation

i.e. one third is allocated to existing plants and two third is allocated to other projects.

Based on the 98% achievement of the investment approved in 2010 tariff review, the BEA

allowed 98% of the remaining planned investments. Taking into consideration above

decisions, the approved investment schedule is as in Table 21.

Table 21 BEAs approved investment schedule

Fixed assets (Nu. mill.) 2013 2014 2015 2016

Land - - - -

Buildings 176.49 245.00 183.91 21.56

Civil structures - - 10.78 63.70

Dam complex 56.51 262.72 19.60 -

Water conductor - - - -

Power house 90.22 443.24 368.35 490.44

Transmission equipment 2.55 17.64 4.90 -

18

Equipment 52.43 39.20 9.89 -


Total 479.66 1,105.90 705.42 686.24

3.1.3 Summary on Depreciations and Return on Assets

The net asset values and annual depreciation has been re-calculated using the TDR

depreciation rates.

The assets that are no longer used by the DGPC and which have been handed over to other

agencies are deducted from the net asset value and depreciations of the DGPC.

Only one third of the Corporate Office net asset values and depreciations of 2012 have been

included in the DGPCs allowances.

The planned annual capitalized investments which are submitted by the DGPC has been used.

Only one third of the Corporate Office investments are included in the investment schedule.

Investments worth Nu 704 million have been removed from the investment schedule, since

they are either not necessary for operating or maintaining the existing power plants or the

costs are already included in some other allowances.

Only 98 % of the remaining investments are included in the investment schedule based on

DGPCs past performance of the approved investment plan 2010-2013.

Based on the review of the assets of 2009, the planned investments for 2010-2013 and the

approved WACC the BEA has approved the allowances for return on assets and depreciations

as given in Table 22.

Table 22 BEAs approved allowances for return on assets and depreciations

RoA and DEP (Nu. mill) 2013/14 2014/15 2015/16

Gross asset values 60,294 61,087 61,992

Accumulated depreciations 17,437 19,694 22,008

Net asset value 42,857 41,393 39,984

Return on Asset (RoA) 5,127 4,952 4,784

Depreciation (DEP) 2,257 2,314 2,368

3.2 O&M allowances

The determination of operating and maintenance costs is described in Section 6.3 of the TDR.

The allowance for O&M costs is calculated each year. The O&M allowance is determined for

the reference year 2012 which will be increased by inflation less efficiency gain targets

through the tariff period. For each year in the tariff period an additional O&M allowance is

added for new assets as per the investment schedule using benchmarks as set out in the TDR

Schedule A. The annual regulatory fees are added to the O&M costs.

3.2.1 DGPC proposal

The Historical O&M allowance figures for the period 2010 2012 proposed by the DGPC are given in Table 23.

Table 23Historical O&M costs proposed by DGPC

2010 2011 2012

19

O&M expenses 302.93 369.41 333.53

Employee Costs 530.58 608.14 677.39

Other Expenses 126.38 115.47 136.27

Total (Nu. mill) 959.89 1,093.02 1,147.18

The O&M allowances of Nu. 1,156 million is proposed by the DGPC for the reference year

2012 based on inflated historical O&M costs for BHP, CHP, KHP and THP in the period

2010-2012.

The DGPC proposed annual addition of O&M allowances are based on an O&M benchmark

of 1.5% of the planned capital expenditure corrected for planned adjustments and removals

during the year as referred under Section 3.1.1. DGPC feels that O&M Benchmark of 1.5% is

reasonable compared to CERC norms, which allows an O&M allowance of 2%

The DGPC has determined the revalued asset cost of as of 2012 as Nu. 110,097 million as per

the revaluation carried out by Cunningham Lindsey International Private Ltd on the asset

value as on 31 December 2011for THP, CHP and BHP and revalued figures for KHP

determined in 2008 adjusted for inflation. The benchmark O&M cost has been calculated by

DGPC to be Nu. 1,651.5 million, which is based on 1.5% of the total replacement value of

Nu. 110,097 million.

The O&M allowances are adjusted for inflation using an average annual inflation rate of

9.03%.The DGPC has proposed using 0 % efficiency gains on O&M costs during the next

tariff period.

The DGPC proposes regulatory fees of Nu.10.36 million per year for the tariff period.

The wheeling charges and power import costs have not been included. However, DGPC

proposes BEA to allow for the full recovery of the cost of power import by allowing such

imports as a pass through to BPC. In addition, DGPC also submits that currently, the

wheeling charges of Nu. 0.111 per kWh on the import energy is also being charged by BPC to

DGPC. Since the import pertains to domestic supply, DGPC proposed that the cost of

wheeling should also be factored into the cost of supply of import energy.

The breakup of the proposed O&M allowances is shown in Table 24.

Table 24Break up of O&M allowances proposed by the DGPC

O&M allowances (Nu. Mill.) 2012 2013 2014 2015 2016

O&M 2012 1156.1 1260.15 1373.56 1497.18 1631.93

O&M additions 2013 investments 7.52 8.20 8.94 9.74

O&M additions 2014 investments 20.49 22.33 24.34

O&M additions 2015 investments 15.88 17.31

O&M additions 2016 investments 12.24

O&M allowances 1156.10 1267.67 1402.25 1544.33 1695.57

3.2.2 BEA review

The DGPC has proposed an O&M allowance of Nu. 1,156 million for the reference year

2012. This figure is equal to the average of the O&M costs adjusted for inflation over the

period 2010-2012. Inflation rates in Table 5 are used. The historical O&M costs estimated by

the DGPC are shown in Table 25.

Table 25 Estimated historical O&M costs for DGPC (2012-values)

O&M costs 2010 2011 2012 Average

20

Nominal values (Nu. mill) 959.89 1,093.02 1,147.18

2012 values (Nu. mill) 1135.73 1185.38 1,147.18 1,156.10

The BEA has verified that the historical O&M costs for the period 2010 to 2012 from the

audited annual accounts submitted by DGPC and decided on the following:

3.2.2.1 Deduction of Corporate Social Responsibility expenses

The BEA has found that DGPC has included Corporate Social Responsibility expenses such

as community welfare expenses and donations in the calculation of the proposed O&M

allowances. The BEA is of the view that donations are not expenses for operating and

maintaining the DGPCs assets related to their licensed generation activities and therefore should not be included in the allowances. Similarly, the community welfare expenses also

should not be included in the allowances. Therefore, the CSR, donation and community

welfare expenses as shown below are deducted from the O&M costs.

Table 26 Expenses to deducted from O&M costs

Other incomes 2010 2011 2012

Community Welfare Expenses 4.76

Donations 11.81

CorporateSocialResponsibility 16.20 15.60

Total 16.57 16.20 15.60

3.2.2.2 Deduction of incomes from rent and hire charges

The DGPC has several sources of incomes other than electricity revenues. In BEAs opinion, incomes from recovered house rent and hire charges for equipment should be deducted from

the costs before the allowances are calculated. The cost of houses and equipment that are

already recovered through other incomes should not be socialized in the tariffs. Therefore,

income from house rent and hire charges as shown below in Table 27are deducted from Other

incomes.

Table 27 Incomes to be deducted from O&M costs

Other incomes 2010 2011 2012

House rent recovered- Employee/Others 13.28 13.81 13.66

Hire charges equipment 0.83

Total 14.10 13.81 13.66

3.2.2.3 Inclusion of Corporate Office Expenses

The Corporate Office O&M expenses of Nu. 38.94 million in 2010, Nu. 308.01 million in

2011 and Nu. 193.76 million were allocated to the existing plants. Since most of the O&M

expenses for the Corporate Office relate to the new investments, only one third of the O&M

expenses of the Corporate Office shall be included in the O&M allowance.

3.2.2.4 Inclusion of License fees and other income

The BEA licence fees of Nu. 10.36 million per year has been included in the O&M costs,

since the licence fees is added separately, the BEA licence fees should be deducted.

21

DGPC also recovers the cost of supplying electricity to its staff and private parties. Since the

cost of providing services are included in the DGPCs costs, the revenue should be deducted from the O&M costs to avoid double recovery of such costs.

After considering the above, the BEA estimates the average historical O&M costs to Nu

968.97 million as shown in Table 28.

Table 28 BEAs estimated historical O&M costs for DGPC (2012values)

O&M costs Nu. mill. 2010 2011 2012 Average

DGPC estimates 959.89 1,093.02 1,147.18

P&L Statement 939.48 1,090.29 1,141.49

Difference -20.41 -2.73 -5.70

CSR -16.57 -16.20 -15.60

Other incomes -14.10 -13.81 -13.66

Corporate Office expenses -25.96 -205.34 -129.17

BEA License Fees -10.36 -10.36 -10.36

Electricity revenue from staff -0.43 -0.56 -0.56

BEA estimates 872.06 844.02 972.13

BEA estimates - 2012values 1,015.99 918.80 972.13 968.97

3.2.2.5 O&M benchmarks

The DGPC has determined the re-valued asset cost of the BHP, CHP, KHP and THP to be

Nu. 110,097 million. All assets pertaining to civil works and plant and machinery were

considered except for other assets such as office equipment, vehicle and furniture. The

methodology of valuation was based on the fixed asset register and using indices adjusted for

the price movement in the specific industry groups from government data and procurement

costs in India. DGPC did not revalue the assets of KHP and the new replacement cost has

been derived based on the re-valued figures determined in 2008 adjusted for inflation. Based

on the replacement value of Nu. 110,097 million, DGPC has worked out the benchmark

O&M cost as Nu. 1,651.5 million, based on 1.5% of the total replacement value.

Table 29 Current replacement costs (CRC) of fixed assets and O&M benchmarks.

Plants CRC

Nu. mill 1.50 % 1.05 % 1.00 %

BHP 5,772.64 86.59 60.61 57.73

CHP 21,880.68 328.21 229.75 218.81

KHP 8,896.46 133.45 93.41 88.96

THP 73,548.16 1,103.22 772.26 735.48

Total 110,097.93 1,651.47 1,156.03 1,100.98

The benchmark O&M cost for 2012 is calculated as Nu 1,651.5 million by DGPC, using the

O&M benchmark of 1.5 % of the Current Replacement Cost (CRC) as proposed by the

DGPC. However, Schedule A in the TDR states that benchmarks for operating and

maintenance costs for large hydropower generation shall be between 1.0 % and 1.5 % of

capital costs, adjusted by the change in the consumer price index since installation. Using the

proposed level of Nu. 1,156 million as O&M allowances for 2012, the O&M/CRC ratio is

1.05 %. Using the O&M benchmark of 1 % results in an O&M allowance amount of Nu.

1,101 million. However, the O&M allowance determined by the BEA of Nu. 968.97 gives a

ratio of 0.9 %. These figures indicate that the proposed level of benchmark of 1.5 % is too

22

high for the new assets. Since none of the asset additions in the next tariff period are new

generation assets, but mainly up-gradation or replacement of existing assets, equipments,

tools and ICT which are not likely to increase the O&M costs significantly, therefore the BEA

has decided to use an O&M benchmark of 1 % for asset additions in the next tariff period.

3.2.2.6 O&M Efficiency gains

The DGPC has proposed 0 % O&M efficiency gains through the next tariff period. The

DGPC submitted that the O&M efficiency gain is proposed as 0% considering that the actual

historical increases in O&M costs are higher than the 5% increases allowed for inflation as

shown in Table 30. DGPC expects increases in O&M costs in the future due to the ageing of

the power plants and rising human resources costs. DGPC submits that O&M efficiency gain

of 0% should be considered since the historical O&M cost, which is less than benchmark

O&M allowances. DGPC submits that there is no further opportunity to improve the O&M

cost efficiency.

Table 30 Historical O&M cost increases

2009 2010 2011 2012

O&M costs 149.42 302.93 369.41 333.53

Employee costs 458.22 530.58 608.14 677.39

Other expenses 89.91 105.98 115.47 136.27

Actual O&M Costs 697.55 939.49 1,093.02 1,201.68

% Increase 16 % 10 %

Inflation 9.10 % 8.45% 9.54%

The BEA does not regard the comparison of the development of the DGPCs O&M costs with the inflation rate for the period 2010-2012 as relevant when setting the regulatory efficiency

targets for the next period. The BEA assumes that one of the main reasons for the

extraordinary increase in O&M cost is due to increase in employee remuneration and benefits

in the DGPC, which is not a relevant benchmark for the future.

Neither is the BEA aware of any changes in the mandate of the DGPC related to their current

generation licence which should require any significant increase in O&M costs.

The BEA is of the view that several conditions have indicated that there should be

possibilities of efficiency gains in the next tariff period: (1) Since Bhutan is a fast developing

country, a general increase in efficiency should be expected; (2) the DGPC states in their

investment plan that several of their investments will reduce operation and maintenance costs

(3) the amalgamation of the four power plants into one company should increase the

efficiency.

Based on this view, the BEA has decided to fix an annual O&M efficiency gain target of 2 %.

3.2.3 Cost of imports

Import of power from India is necessary for the BPC to meet the domestic HV demand during

the lean season and should be included in the BPC HV tariff. The BEA recognizes that the

DGPC import may be a practical way of arranging some of the import requirement. The

DGPC can charge BPC for the power import from India at the tariff determined by BEA.

3.2.4 Conclusions on O&M allowances

23

The BEA has deducted the Other incomes such as hires, rents and electricity revenue from

staff, Corporate Social Responsibility expenses, community welfare expenses, Corporate

Office expenses and regulatory fees shown in Table 28 from the calculation of the 2012 O&M

allowances.

The BEA has decided to use the amount of Nu. 968.97 million, which is the average of the

O&M costs in 2010-2012 adjusted for inflation and the factors described above, as the basis

for the O&M allowances.

The BEA has decided to use an O&M benchmark of 1.0 % for asset additions in the coming

tariff period and an annual O&M efficiency gain target of 2 %.

3.3 RoWC allowances

The RoWC is the allowances for Return on Working Capital in million Ngultrum, in the TDR

Section 8.1.1. which is determined as:

SINVENTORIE365

ARREARSREVWACCRoWC

Where

WACC is the weighted average cost of capital, as determined in accordance with the TDR section 6.6; the WACC is described in Section 2.2in this review;

RoADEPOMREV where OM, DEP and RoA is as described in Section 3.1 and 3.2in this review;

ARREARS is the allowed days receivables, in days;

INVENTORIES is the allowance for inventories, in million Ngultrum.

The purpose of the RoWC allowances is to compensate for the loss of revenues caused by the

lag between the time the costs occurs and the time of receivables from the customers.

3.3.1 DGPC proposal

The DGPC proposed allowances for RoWC per year as shown in Table 31.

Table 31 DGPCs proposed allowances for RoWC

2013 2014 2015

RoWC (Nu. mill.) 379.8 387.2 396.5

Their proposal is based on average arrears of 57 days, inventories of Nu 499.79 million in

2012 values and OM, DEP and RoA allowances as described under the DGPC proposals in

Section 3.1and 3.2 in this review.

3.3.2 BEA review

3.3.2.1 Arrears

The DGPC has proposed average arrears of 57 days. According to the DGPC, the proposal is

based on Memorandums of Understanding (MoUs) between Bhutan Power Corporation

(BPC) and Tala (THP), Chhukha (CHP), Basochhu (BHP) and Kurichhu (KHP) hydropower

plants. The bill preparation and delivery duration is the same for all plants, whilst the bill

24

payment duration varies. Their proposal is to use the arithmetic average of the arrears for each

of the plants. The figures for the proposal are listed in Table 32.

Table 32 DGPCs proposed arrears

Arrears (No of Days) BHP CHP KHP THP Average

2013 Generation Forecast(GWh) 292 1770 359 4442

Average consumption duration 15 15 15 15

Bill delivery duration 10 10 10 10

Bill payment duration 30 30 60 30

Arrears 55 55 85 55 57

The BEA has received copies of MoUs on bulk sale and purchase of electrical energy between the BPC and the hydro power plants. The MoUs state the bill preparation, delivery duration and the bill payment duration for THP, KHP, CHP and BHP. The arrears has been

calculated as the weighted average using each plants generation forecast for the regulatory period as weights, the BEA has calculated the average arrears of 57 days, which is approved

to be used in this review.

3.3.2.2 Inventories

The DGPC proposes total inventories of Nu. 499.79 million which is the inventories for the

year 2012. DGPC submits that the cost of inventories has been increasing every year and this

is expected as the plants are ageing. Since the proposal is to maintain the inventories at the

2012 level, BEA considers the proposed inventories to be reasonable compared to the size of

the company.

3.3.3 Conclusions on the Return on Working Capital

The BEA has decided to use arrears of 57 days and inventories of Nu. 500 million.

3.4 Energy Volumes

The annual energy volumes are used to calculate the average cost of supply per unit per year,

which will be the approved generation tariff. The average cost of supply is calculated by

dividing the discounted total cost of supply on the discounted annual energy.

The annual energy volumes shall be determined as the Design Energy for each power station

owned by the Licensee adjusted for auxiliary consumption and availability, determined in the

TDR Section 8.1.2:

i

iiiAVAILAUXENERGYENERGY )1(

The Design Energy is defined as the total energy which could be generated in 90%

dependable year with 95% installed capacity of the station in the Tariff Determination

Regulation.

3.4.1 DGPC proposal

3.4.1.1 Design energy

The design energy in the Detailed Project Reports for each of the plants is calculated as the

energy in a 90% dependable year with 100% installed capacity. Since the design energy is

defined in the TDR as the total energy which could be generated in 90% dependable year with

25

95% installed capacity of the station, the DGPC has estimated the design energy for Chukha,

Kurichhu and Tala using the information in the Detailed Project Reports, by using only 95%

of the installed capacity. However, DGPC submits that a review of the generation

achievements against the design energy reveals that since full commissioning about 25 years

ago, CHP has achieved design energy only for 15 years, and KHP in 8 years of operation has

never achieved design energy generation. DGPC attributes this to inconsistent sources of

hydrological data or insufficient number of years of data available particularly in the case of

the Wangchhu and Kurichhu at the time of preparation of DPRs or declining hydrological

conditions that is being experienced. Due to such inconsistencies; DGPC reviewed the design

energy for CHP, THP and KHP based on the Indian Central Electricity Authority (CEA)

recommendation to consider 1979-80 as 90% dependable year, the design energy of CHP and

THP has been worked out by DGPC as 1,623 GWh, and 3,886 GWh respectively. The design

energy for KHP was recalculated based on the actual hydrological data collected during the

operation stage from 2004 to 2011 as 358 GWh.

DGPC has also incorporated the design energy from the Tichhalumchhu and Lubichhu

diversion schemes. The expected energy from the Tsibjalumchhu Diversion Scheme to the

THP has been incorporated from 2014 onwards on commissioning sometime in mid 2014.

The revised design energy of CHP, THP and KHP and design energy of BHP as per the DPR

as summarized is recommended and used by DGPC as the input of Design Energy in the tariff

model.

However, DGPC has proposed using average annual energy less 15% royalty energy instead

of design energy in their proposal.

3.4.1.2 Forecasted generation

The energy generation forecast for 2013 as given in Table 33is based on the projections in the

DGPC Budget 2013.

Table 33 Forecasted generation (GWh)

Plants 2013 2014 2015 2016

BHP 292.00 292.00 292.00 292.00

CHP 1,769.83 1,769.83 1,769.83 1,769.83

KHP 359.12 359.12 359.12 359.12

THP 4,442.16 4,442.16 4,442.16 4,442.16

Tsibjalumchhu - 31.00 93.00 93.00

Total 6,863.11 6,894.11 6,956.11 6,956.11

DGPC generation forecasts are based on past years generation and is used as input for the average annual energy. For the tariff period, the same average annual energy has been used

since forecast for the following years are not available. The Tsibjalumchhu diversion Scheme

to THP is expected to be commissioned in the middle of 2014 and therefore the expected

energy from this has also been factored in from 2014 onwards.

3.4.2 BEA review

The average generation, forecast generation, design energy (DPR), design energy (TDR) and

revised design energy (DGPC) of the DGPC plants have been compared in Table 34.

26

Table 34 Comparison of generation energy volumes (GWh)

Plants Average

generation

(2003 -2012)

Forecasted

generation

(2013)

Design

Energy

(DPR)

Design

Energy

(TDR)

Revised Design

Energy

(DGPC)

Design Energy

(TDR) +

revised design

energy KHP

BHP 287.1 292.00 291.00 291.00 291.00 291.00

CHP 1838.1 1,769.83 1,871.95 1,822.35 1,623.14 1,822.35

KHP 368.1 359.12 400.00 387.88 358.43 358.43

THP 4441.0 4,442.16 3,962.00 3,885.89 3,886.22 3,885.89

Total 6934.5 6,863.11 6,524.95 6,387.12 6,318.79 6357.67

The average actual generation of the DGPC for the period 2003-2012 is approximately

547GWh more than the design energy as per the TDR. Moreover, DGPC has also forecasted

generation of 6,863.11GWh which is much closer to the average actual generation than the

design energy.

The DPR of Tsibjalumchhu has been verified for the additional energy generation.

Since the TDR clearly states that the tariff calculations should be done by using design

energy, the BEA approves the use of design energy as per TDR for BHP, THP and CHP.

However, since KHP in its 8 years of operation has never achieved design energy generation,

it seems reasonable to use the revised design energy calculated by DGPC as 358.43 GWh.

Therefore, use of 6357.67 GWh as the design energy for DGPC existing plants and additional

energy generation of 31 GWh in 2014 and 93 GWh in 2015 onwards is approved to be used.

DGPC has proposed using average annual energy less royalty energy instead of design energy

in their proposal. BEA views that royalty energy deduction not allowed according to the TDR

and royalty is a tax imposed on the generators by the Government and BEA doesnt have the mandate to pass it to the customers. Therefore, royalty energy should not be deducted from

the design energy.

4 Tariff determination

As per the TDR Section 8.1.3, the average cost of supply shall be taken as the ratio of the

discounted annual costs of supply to the discounted energy volumes, with discounting applied

over the Tariff Period using the WACC, as follows

TP

n

nn

TP

n

nn

WACC

ENERGY

WACC

TC

AC

1

1

)1(

)1(

The BEAs review has resulted in the allowances for the next tariff period as shown in Table 35 below. The WACC is decided to be 11.96 %, ref. Section 2.2.3.5.

27

Table 35 - BEA's approved allowances for the DGPC

2013/14 2014/15 2015/16

OM 1,046 1,118 1,191

DEP 2,257 2,314 2,368

RoA 5,127 4,952 4,784

RoWC 222 226 231

Total Cost 8,652 8,611 8,574

Energy 6,156 6,186 6,246

By discounting the Total Cost of Supply (TC) and the Energy using a WACC of 11.96 %, and

applying the formula from the TDR Section 8.1.3, the BEA has determined the Additional

Price to be 1.39 Nu/kWh.

4.1.1 Royalty Energy, Royalty Price and subsidies

The Royalty Energy is the energy to be provided by the DGPC to the BPC in accordance with

the TDR. The Royalty Price is the price in Ngultrum per kWh determined by the BEA for

Royalty Energy.

The purpose of the Royalty Energy and Royalty Price is to transfer a subsidy from the RGoB

to the BPCs customers in accordance with the policy of the Minister, by bringing down the BPCs cost of supply.

The Lhengye Zhungtshog has decided that the Royalty Energy volume shall be 15% of the

annual average energy expected to be generated by the DGPC adjusted for auxiliary

consumption. The expected Royalty Energy volume is shown in Table 36 which is calculated

based on the expected power generation from the DGPC.

Table 36 Expected Royalty Energy volumes

2013/14 2014/15 2015/16 Average

Royalty Energy (GWh) 1,043 1,048 1,057 1,049

Further, the Lhengye Zhungtshog has decided to utilize the full annual average royalty energy

volume of 1,049 GWh valued at the approved domestic generation tariff of Nu. 1.39/kWh to

subsidize the LV and MV consumers. The total approved subsidy amount of Nu. 1,458

million has been allocated by the Lhengye Zhungtsog to be transferred to various customer

groups as shown in Table 37.

Table 37 Subsidies allocation in mil Nu.

2013/14 2014/15 2015/16

LV 1,271.704 1,271.704 1,271.704

MV 186.296 186.296 186.296

HV 0 0 0

Total 1,458 1,458 1,458

28

As per the TDR Section 8.2.3, the Royalty Price shall be calculated according to the formula:

TP

n

nn

TP

n

nn

WACC

ROYALTY

WACC

BSU

ACRP

1

1

)1(

)1(

Where

RP is the Royalty Price in Ngultrum per kWh;

AC is the average cost of supply;

TP is the number of years in the Tariff Period;

SUBn is the subsidy amount in million Ngultrum in year n;

ROYALTYn is the amount of Royalty Energy in year n

WACC is the weighted average cost of capital, as determined in

accordance with Section 6.6 in the TDR.

Based on this formula and the approved subsidy amounts and Royalty Energy volumes, the

BEA has determined the Royalty Price to be zero for the tariff period 1st October 2013 to 30

th

June 2016.

Documents

DGPC Tariff Review Report 2013