IPP Report PDF
IPP Report PDF
IPP Report PDF
Power Sector
COMMITTEE FOR POWER SECTOR AUDIT, CIRCULAR
DEBT RESOLUTION & FUTURE ROADMAP
March, 2020
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Table of Contents
List of Tables
Table 1 - Regional Comparison Of Cost Of Electricity 6
Table 2- Returns Offered To Ipps Set Up In Pakistan 8
Table 3 - Overview Of Excess Payments On Account Of Systemic Errors 14
Table 4 - Savings From Shifting To PKR Based IRR At USD-PKR Parity Of First Year After Cod 16
Table 5- Savings In Case Of Shift To TAP
16
Table 6 - Policy Wise IPP Overview
Table 7 -Fuel Mix Under All Policies 37
38
Table 8- Overview Of lpps Established Under The 2002 Policy
39
Table 9 - IPP Wise Detail Of Profitability And Payback
40
Table 10- IPP Wise Detail Of Profit Before Tax 41
Table 11 - IPP Wise Detail Of Dividends 41
Table 12- Adjustments Made To Arrive At Adjusted Profit 42
Table 13 - 2002 lops: Details Of Excess Profits And Dividends 44
Table 14- Detail Of Average Annual Excess Roe 45
Table 15 - Detail Of Excess Profits From Fuel Cost And O&M Savings 45
Table 16- Future Forecast Of Excess Profit If Status Quo Is Maintained 47
Table 17- Impact Of Duplication Of Currency Depreciation In Roe Under 2002 Policy 49
Table 18- Detail Of Excess Roe Paid: IRR Miscalculation 49
Table 19 - Total Savings: Miscalculation In Debt Component Of CPP 50
Table 20- Extra Earnings: Shortfall In RFO Inventory Levels 51
Table 21 -2002 Policy: IPP Wise Excess Earnings 51
Table 22 - Share Capital With Profit Earned, Dividend Withdrawn, Etc. 53
Table 23- Energy Mix Under The 2015 Policy 55
Table 24- lpps Under The 2015 Policy 56
Table 25- NEPRA Determined Tariff By Thermal Efficiency 56
Table 26 - NEPRA Determined Project Cost For Imported Coal 57
Table 27- Excess Setup Cost Allowed To Ipps Under 2015 Policy 58
Table 28 -2015 Policy: Excess Payments 60
Table 29 - Wind laps Under 2006 Policy 61
Table 30 - Wind lops: Profits And Dividends 62
Table 31 - Annual Returns Earned By Wind lops 62
Table 32- Wind laps: Projected Excess Return Over Life Of Project 64
Table 33 - Solar lops Under 2006 Policy 65
Table 34 -Solar Ipps: Profits And Dividends 66
Table 35- Solar 'pips: Annual Returns Earned 66
Table 36- Projected Excess Return Over Life Of Solar lops 68
Table 37 - 2013 Upfront Tariff For New Bagasse Co-Gen 69
Table 38 - 2013 Co-Gen Ipps 69
Table 39- Bagasse lops Under Review 70
Table 40- Excess Profitability: IRR Miscalculation 72
Table 41 - Excess Profitability Fixed Costs And Debt Service Costs 72
Table 42- Summary Of Excess Profits By 2015 Ipps 76
Table 43 - Returns Being Offered To Different Technology Power Plants 80
Table 44 - Comparison Of Return With And Without USD Indexation 81
Table 45- Savings: Switching From USD To PKR Based Returns 83
Table 46- Difference Between Termination Cost And Excess Capacity Payments 87
Table 47 - 2002 Policy: Financial Impact Of Termination 87
Table 48 - NTDC System - Cost Of Generation Vs. Average Selling Price (PKR/Kwh) 96
Table 49 - NTDC System - Cost Of Electricity Generation 97
Table 50- WA PDA: Generation, Sales Revenue And HP (Rs. Million) 102
Table 51 - Electricity Generation With And Without T&D Constraints (FY2020) 102
Table 52- Consumption Wise Sales Mix Of Discos 105
Table 53- Break-Down Of Power Sector Receivables (PKR Million) 109
Table 54 - DISCO Wise Amounts Due From Running And Disconnected Defaulters 110
Table 55 - Loading Position Of DISCO Transformers 111
Table 56 - Province Wise Network Analysis 111
Table 57 - Discos' Receivables At End Dec-2019 (Rs. Million) 114
Table 58 - Estimated Cost Of Electricity FY2020 117
Table 59- Cost Of Electricity: Captive Power Vs. Grid Electricity 122
Table 60 - Captive Power Generation In Service Areas Of The Two Public Grid Systems 123
Table 61 - Financial Impact Of Losses And Under Recoveries 129
Table 62- Equity Position Of Discos FY2018 131
Table 63- QESCO Units Purchased To Network Ratio Relative To All Discos 133
Table 64- Electricity Tariff For Domestic Sector (PKR/Kwh) 134
Table 65 - Regional Comparison Of Cost Of Electricity 138
COMMITTEE FORMATION AND MEMBERSHIP
This report has been prepared in accordance with Notification No. IPP-01(12)/2017
issued by the Ministry of Energy (Power Division) on August 7, 2019, under directions
of the Prime Minister of Pakistan, whereby a Committee was constituted to identify
and examine the causes of high cost of electricity in the country, including review
of private power producers, ways to resolve circular debt and inefficiencies in the
transmission and distribution sector, and suggest a future roadmap for the power
sector structure ("the Committee"). The terms of reference and the composition of
the Committee are enclosed at Annex A.
Any work of this magnitude, without adequate financial and human resources, is
bound to suffer oversights given the sheer volume of data which was required to
be prepared and analyzed in this short time-period. This is despite the fact that
Committee has exercised extreme diligence in checking every figure and its
calculation.
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Sajjad Bajwa - FIA
Nauman an -Secretary
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FOREWORD
4.
During the course of compiling this report, we were asked how can we engage all
the stakeholders in a conducive environment to resolve power sector issues. This is
one of the major challenges towards achieving resolution to deep and complex
issues of the power sector which is holding back Pakistan's public, economy and
industries from achieving their true potential. These issues have resulted in a cost of
power which is unsustainable across most economic classes and industrial segments
in the country.
5.
Power sector policies during the last two decades have allowed exorbitant profits
to a select group of investors and encouraged de-industrialization by incentivizing
higher capital allocation to a guaranteed and less risky power business. During this
time, inefficiencies in the public sector generation and distribution companies were
unfortunately tolerated, including by the Federal Government and NEPRA. The
reform towards the goal of the ultimate privatization of ex-WAPDA distribution
companies has been pending since more than two decades. These companies
have been corporatized with independent Boards of Directors, yet operationally
this entire distribution sector worth Rs. 1,400 billion is being managed by the Federal
Government.
6.
During the 30-year period between 1990 and 2019, the dynamics in the global
financial markets as well as opportunity cost of investments and returns offered to
power sector investors around the world went through many changes. In Pakistan,
we remained stagnant in our offering of unjustifiably high guaranteed returns
indexed to the US Dollar to investors, presumably in the hope of attracting foreign
investment. This is despite the fact that over this period there has been an
improvement in the expertise and learning of the local pool of potential investors in
the power sector.
7.
Consequently, the Federal Government has continued taking responsibility for
payment obligations of all costs and investments because of a resistance against
transitioning to competitive power markets. This is a classic example of the damage
caused to the economy because of partial reform.
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8. Today, the country's domestic and international debt levels have reached the
point of unsustainability because of which power sector issues require even more
urgent redressal. If we do not act soon, we risk economic chaos. Unfortunately,
none of the problems have easy solutions. Most require disruptions and losses to
certain stakeholders in the short-term if we want to achieve gains in the long-term
for all stakeholders. Though it is obvious from this analysis that various mistakes were
committed which are part of a natural learning process for policymakers exploring
structural changes, it is also obvious that the system and processes were
manipulated to the benefit of a select few.
9. In order to find permanent solutions which can benefit the country, a three-pronged
approach is needed:
11. Each of these steps are mandatory if we are to move forward, and that is where
accountability will really matter, accountability of stakeholders who deliberately
resist the move out of the status quo.
12. We were fortunate to attract some of the best minds from different institutions for
the Committee who were not only patriotic but were also willing to work hard,
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disagree strongly and debate each issue passionately. At the same time, we were
unable to procure a budget allocation because of which we were limited in
obtaining technical and legal support. We have done as best as was possible given
our current resources and have recommended areas in the report where the
Federal Government ought to separately engage technical and legal experts to
look deeper into those issues.
Be that as it may, in a sector which is assessed to be losing around Rs. 1000 million
daily, a budget allocation of Rs. 22 million to obtain the best international expertise
(-7
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to suggest ways to stop this bleeding of public money was not something we had
expected to be denied.
This work could not have been completed without the support of Mr. lmran Ahmad
Khan, FCA, for providing us with analysts who helped prepare detailed worksheets
based on more than 450 financial statements and spent an endless number of hours
with our team in CPPA-G. Several other individuals came forward and offered their
knowledge, wisdom and support towards this effort. We cannot cover all names
here and have tried to highlight the presentations and some of the meetings the
committee had in Annexure B. The support staff provided by NEECA was also
We are grateful to Mr. lmran Khan, the Honorable Prime Minister of Pakistan, for
realizing the gravity of the issues in the country's power sector and taking the
initiative towards formation of this committee. We would also like to thank Mr. Omar
Ayub Khan, Honorable Minister for Energy, Mr. Irian Ali, Secretary, Power Division, Mr.
Aamir Khan, Chairman, SECP, Mr. Tauseef H. Farooqi, Chairman NEPRA, as well as
the senior management of CPPA-G, PPIB and NTDC for providing us with some of
th ir best human resources and tremendous support.
Muhammad Ali
Chairman
Committee for Power Sector Audit, Circular Debt Resolution
and Future Roadmap
March 16, 2020
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EXECUTIVE SUMMARY
BACKGROUND
16. Pakistan has the highest cost of electricity across all major consumer segments in
the region. Given that our exports rely on low value-added products, some of which
are heavy on electricity consumption, this high cost of electricity has reduced the
competitiveness of our exports, thereby impacting the country's trade deficit and
balance of payment.
3 Bangladesh
Currently, the average tariff in the country as well as cost of generation are at their
highest levels. It is in this background that the Committee was tasked to conduct a
holistic analysis of the causes behind the issues faced by the sector.
The Committee divided its review over three parts and proposed an overall action
plan consolidating its recommendations in the last section. This is followed by
individual IPP-wise reports. Accordingly, this report is divided into five main sections:
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19. During the course of its work, various sources identified malpractices by private
sector generation companies to the Committee, especially with respect to project
set-up costs, actual fuel usage being less than invoices submitted to NEPRA,
kickbacks in commission on fuel, etc. Since its mandate was restricted to a review
of the record made available to the Committee, this Report does not cover such
issues. However, a detailed audit has been recommended in order to verify these
allegations.
Despite its best efforts, the Committee was not provided with the break-up of bulk
power upfront tariff, including Return on Equity ("RoE") used under the 1994 policy,
because of which it was constrained to undertake only a limited review of the IPPs
set up under the 1994 Policy.
With respect to the relevant financial statements, various adjustments were made
to arrive at the true profitability of IPPs, which was lower than the profitability
reported. This is because the debt servicing component (principle and interest) is
shown as part of revenue in the first ten years of IPPs' operations whereas fixed
assets are depreciated over the project life of 25-30 years. Certain other
adjustments were also made to cater for distortions due to the accounting policy
used.
2 https://nepra.org.pk/
3 www.cppa.gov.pk
4 httP://WWW.PPlb.g0V.Pki
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Overview of IPP Profitability
23. Historically, IPPs have been offered extremely attractive return formulas, as evident
from the following table:
Thermal
Imported Coal 17.00%
RLNG 16.00%
Local Gas 15.00%
Thar Coal 20.00%
Ba asse 17.00%
Renewable
Solar! Wind 17.00%48%
H dro 17.00%
The first IPPs were established under the 1994 pol cy, with HUBCO having set up even
earlier. We therefore have 20 years of data which allows us to evaluate the impact
which our previous policies have had in terms of investment incentives offered to
power generation.
Under the 1994 Power Policy, 16 out 17 IPPs invested a combined capital of Rs.51.80
billion and have so far earned profit in excess of Rs.415 billion, having taken out
dividends in excess of Rs.310 billion. It needs to be kept in mind that both numbers
are understated since they are based on the 275 financial statements available
with NEPRA and SECP out of the total 312 statements required.
Most of these IPPs had an investment payback period of 2-4 years, profits generated
were as high as 18.26 times the investment and dividends taken out as high as 22
times the investment. Six companies earned average annual RoE between 60-79%
and four companies earned RoE of around 40%. These profits are probably unheard
of in any other sector, especially with such low level of risk and guaranteed
payments by the government.
Moving forward, 13 Residual Fuel Oil ("RFO") and gas-based plants with a combined
capacity of 2,934 MW were established under the Power Policy of 2002. During the
last 8-9 years of operations, these companies have so far earned profits of Rs.203
billion against their combined investment of Rs.57.81 billion. Even after adjusting for
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debt component to arrive at the true profitability, the companies still earned Rs.152
billion in profit and made dividend payments to the tune of Rs.111 billion.
The
individual profitability among these companies also varies, with some showing a
much higher profit to investment ratio than others, with the average annual RoE as
high as 87%, profits of around 9 times and dividends up to around 7 times their
investment.
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In the case of the IPPs established under the Power Policy of 2002, it was found that
a major component of excess payments to the IPPs were on account of the actual
fuel consumed to generate electricity being less than the payment made by the
purchaser in lieu of the use of such electricity. Similarly, the actual O&M expenses
incurred by the producer were less than the payment received under this head.
Total excess payments made under these and other heads works out to Rs. 64.22
billion during the last nine years with expected future excess payments of Rs. 145.23
billion during the remaining years of operations bringing the total excess payments
of Rs. 209.46 billion to these plants.
Further, while determining tariffs for RFO based IPPs, NEPRA had approved their
'heat rate"5 on the basis of information provided by the respective IPPs. The actual
heat rate submitted by one of the IPPs which has consistently operated at higher
efficiency levels than those submitted to NEPRA is attached at Annexure 1C. This is
applicable in case of most of the IPPs.
Similarly, the O&M component of tariff was based on the estimates provided by the
IPPs, which was consistently higher than the actual expenses incurred. This also holds
true in case of most of the IPPs.
Excess set-up cost of Rs. 32.46 billion was allowed to the two coal-based plants due
to misrepresentation by sponsors regarding Interest During Construction ("IDC") as
well as non-consideration of earlier completion of plants by NEPRA. These plants
were completed within 27-29 months, however IDC was allowed for 48 months. As
a result, one of the plants, Huaneng Shandong Ruyi (Pak) Energy ("HSR"), commonly
known as Sahiwal Coal Power Plant, was entitled to an excess RoE of USD 27.30
million in annual payment of return, which is indexed to USD and will be made every
year over the entire project life of 30 years. Assuming a 6% annual rupee
depreciation the excess payment over the project life works out to a total of Rs.
291.04 billon.
5 Heat rate is one measure of the efficiency of electrical generators/power plants that convert a fuel into heat and into
electricity. The heat rate is the amount of energy used by an electrical generator/power plant to generate one kilowatt-
hour (kWh) of electricity Id Ips://wvv_ aaviluals/faas/faa.pho?id=1078,k3
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36. Under the 2013 Framework for Co-Generation,
eight bagasse-based plants were set
up with a total capacity of 254 MW. At the time of tariff determination, the Pakistan
Sugar Mills Association reported a Net Annual Plant Capacity factor ("NAPC")
of
45% which was used by NEPRA to recover fixed cost in tariff determination.
However, the Bagasse power plants under review were operating at higher than
45% NAPC and were therefore being paid for fixed cost, debt payment, etc. which
was higher than their actual expense and liability. This has led to excess payments
of Rs. 6.33 billion to the four bagasse-based plants so far.
r--
Any payment with respect to production over and above the minimum benchmark
would lead to an extra payment on account of debt, interest and insurance. Since
these companies have achieved CoD relatively recently, it is too early to quantify
the real impact of this excess payment, however, if not rectified by NEPRA, this tariff
determination methodology is likely to lead to excess payments going forward.
11
At the time of tariff determination, NEPRA calculated IRR for all plants assuming an
annual payment of their returns at year end, i.e. 25 payments assumed if project life
is 25 years. However, CPPA-G makes these payments to IPPs on a monthly basis with
any late payment being subjected to Late Payment Surcharge ("LPS").
A similar systemic error was observed in case of debt payments where NEPRA has
assumed quarterly payment of debt to IPPs whereas CPPA-G makes monthly
payments for the debt component to IPPs with any late payment being subjected
to LPS. This mismatch leads to additional working capital availability for the IPPs. The
cost of working capital is already a part of the tariff awarded to the IPPs based on
a financing cost of KIBOR + 2%. The impact of this timing difference for 13 IPPs set-
up under the 2002 Policy (2,934 MW) aggregates to Rs. 2.14 billion for the period
under review.
Excess payment was also made to certain IPPs set up under the 2002 Policy despite
the IPPs having an inventory shortfall. According to NEPRA's tariff determination, the
RFO based power plants were required to maintain fuel inventories sufficient to
operate the complex for 30 days at 100% load at all times. For this purpose, the IPPs
were allowed a cost of working capital component in the tariff. A review of the fuel
inventory data for these IPPs revealed that they have largely not maintained their
fuel inventory levels, even though these IPPs were receiving payment from CPPA-G
based on the predetermined fuel inventory levels, resulting in excess benefit passed
on of Rs.3.6 billion.
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Another systemic error observed Was conversion of USD based return to PKR based
return without taking into consideration the true spirit of the ECC decision taken on
May 23, 2007.
In 2005, NEPRA had allowed RoE of 15% in PKR based on 10.2% yield on 10-year
Pakistan Investment Bonds (PIB) yield as risk free rate, adding a market risk premium
of around 4% and asset beta of 1.15, which was then re-levered to the IPPs'
proposed capital structure of 75:25. This was used to allow return to all subsequent
power generation companies.
Currency indexation with USD was not allowed since the PIB rate was used as the
risk-free rate which already captures the annual inflation difference and currency
depreciation between USD and PKR. However, the Rupee based RoE was later
converted to a Rupee based IRR formula, which also included Return on Equity
During Construction ("RoEDC"),
a payment which is a rare phenomenon anywhere
else in the world. Eventually, the Economic Coordination Committee of the Cabinet
("ECC"),
without specifying any specific rate of return, allowed return in USD
irrespective of whether the equity being invested was in a local or foreign currency.
47. The PKR based return of 15%, which was based on the PIB yield (10.2%), was
converted to 15% USD based return without considering or adjusting for the USD
bond yield (which is much lower) in place of P113. The continued provision of 15% IRR
based on PIB, along with USD indexation, amounts to duplication of currency
depreciation factor. The impact of this systemic error has so far contributed to
excess payments of Rs. 16.48 billion.
48. The table below highlights the total excess payments made so far and the
payments expected to be made in the future to the IPPs under review.
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Table 3 - Overview of Excess Payments on Account of Systemic Errors
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16-1. it 1 1 .L0.6.4
Payille i'‘i,
'r I 1E ,N, L
Its, in billion
Duplication of currency depreciation' 4,726.56 16.48
Excess fuel and O&M payments 209.46 145.23 64.22
IRR miscalculation 565.88 554.25 11.63
Other Systemic error (debt and plant capacity factor) 12.10- 12.10
Excess set-up cost allowed 323.50 323.50
5,837.5 1,022.98 104.43
Way Forward
49. A review of payments to the IPPs leads to three conclusions:
50. The Federal Government has two options for addressing these issues:
Option 2: The Federal Government can undertake a forensic audit of all companies
with a view to establishing further wrongdoings which were not identifiable under
the scope of this Report. This will include:
Forensic audit of IPPs to verify any over-invoicing in the project cost, fuel
usage, misreporting in financial statements, etc.;
'Impact for duplication in currency depreciation already paid has been calculated for 2002 Policy (2934 MW) however,
the impact for total project life relates to 2002, 2006 and 2015 policies (13,154 MW).
Li
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Check for possible kickbacks in commissions on fuel supplies; and
The Committee had negotiated the terms with an international power consulting
firm to obtain data on set-up cost, heat rates, O&M, etc. in countries with similar
technology as Pakistan around the same time. However, this exercise could not be
completed due to lack of budget approval.
Here, it is important to highlight that a major difference was noticed between the
set-up cost of a government owned coal-based project initiated through a
GENCO, i.e. Jamshoro Power Company Limited and HSR (Sahiwal), an upfront
imported coal project of similar technology.
P Jamshoro's EPC cost is USD 0.66 million per MW compared to the HSR's Capex
approved at CoD under upfront tariff of USD 1 million per MW. Though the two costs
are not truly comparable as Capex includes non-EPC cost also, a USD 450 million
difference in the two costs does raise a red flag about the authenticity of the latter's
Capex amount.
In order to fix these anomalies of the past, and to bring our cost of generation to
sustainable and affordable levels for the country and consumers, the following
immediate steps are proposed:
Put in place a claw back mechanism for sharing efficiency gains in the
future subject to verification of set-up costs, periodic heat rate testing, etc.
The table below highlights the payments to IPPs under the existing
arrangement versus payments required in case the shift is made to PKR
based IRR at USD-PKR parity of first year after CoD for all plants except 1994
Policy (13,154 MW), leading to savings in excess of Rs. 4,700 billion over the
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project life of these IPPs. On an annual basis, this can lead to saving of at
least Rs. 150 billion which will reduce power tariff in the country by Rs. 1/KWh.
Table 4 - Savings from shifting to PKR based IRR at USD-PKR Parity of First Year
after CoD
wire Total RoE expee _ [...1
''-under
Total RoE expected first year USD • 1
Policy existing arrangement COD
Rs. in billion
2002 (2,934 MW) 595.43 252.19
2015 (8,253 MW) 6,514.31 2,547.39
2 Imported coal (2,640 MW) 2,083.82 8 4 87 _
Hub + Engro Thar (1,980 MW) 1,562.87 6.15
RLNG (3,633 MW) 2,867.62 1,121 37
RE 2006
Wind (1,233 MW) 619.26 336.69
Solar (480 MW) 190.86 86.97
Bagasse (254 MW) 73.08 43.14
7,992.94 3,266.38
d. Finish Take or Pay ("ToP") contracts and move to Take and Pay ("TaP").
to
Name Capadty Payment uti zatliFoanct(t), TaP
(Rs. billion)* li
v:ini;dliupen
:Rs
1 Liberty Power Tech 4.65 5070 2.35
2 Atlas Power Limited 4.98 36% 3.17
3 Mock Gen Limited 2.86 39% 1.11
4 Nishat Power Limited 4.50 46% 2.45
5 Nishat Chunian Power Limited 4.27 65% 2.45
6 Foundation Power Limited 4.08 88% 0.48
7 Orient Power Limited 4.21 49% 244
8 Sapphire Power Limited 4.84 41% 2.83
9 Engro Energy limited 3.65 82% 0.64
10 UCH 11 9.50 94% 0.58
11 Salt Power Limited 4,18 62% 1.59
12 Huaneng Shandong Ray! - Sahiwal 42.43 80% 8.38
Total 94.15 28.18
*Actual capacity payment FY 2018-19 with actual plant factor
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55. Next year's CPP projection by CPPA-G is in excess of Rs. 900 billion. With the current
excess capacity of 30% in the country, moving to TaP and accounting for demand
in growth, the country can easily save at least Rs. 150-200 billion,
which can lead to
further reduction of Rs. 1/KWh in power tariff.
56. The report proposes a detailed, policy-wise roadmap for shifting to TaP contracting
by continuing to guarantee the debt payment but reducing the guarantee of
return payment to 10 years instead of the current 25/30 years. This will also ensure
early inclusion of the plants in the competitive power market structure.
In case any of the 1994 or 2002 plants do not agree to shift to TaP,
the government
may move towards retirement of these plants in the light of the relevant clauses of
the lAs and PPAs. A study of these clauses as well as Tentative Dispatch Plan 2020
(prepared with help of SDDP Software) was undertaken, which analyzed the past
six-months and expected future utilizations of the plants. Plants with less than 3%
future expected utilization (as per NTDC's estimate) have thereby been identified
for the purpose of shut down.
Based on this methodology, a total of 9 power plants under the 1994 Policy and 5
power plants under the 2002 Policy have been shortlisted. However, before arriving
at a final decision regarding retirement, a technical feasibility in this regard may be
carried out to address constraints which may arise due to closure of these plants.
Ct
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1
CIRCULAR DEBT
Background
60. Between FY2005 and FY2010, the cost of generation in the country increased by
148% and average tariff by 33% on account of increased international oil price,
higher share of furnace oil in electricity generation and PKR depreciation. Circular
debt started to emerge in the late 2000s. Successive governments relied on heavy
budgetary support and quasi-fiscal financing to eliminate it, however the measures
addressed the symptoms and not the root causes.
61. The cumulative budgetary support to the power sector amounted to Rs. 3,202
billion from FY2007 to FY2019 comprising:
Yet, the circular debt stock has continued to grow and increased by PKR 465 billion
in FY2019 to around Rs. 1,600 billion, leading to total financial loss to the country of
Rs.4,802 billion during the 13-year period causing annual loss of around Rs. 370
billion due to the Power sector inefficiencies.
62. This is especially alarming because, with public indebtedness (public debt/GDP)
having increased to 85% in FY2019 from 52% in F12007, the government's ability to
provide fiscal support to the sector is now severely constrained.
7 Part of Rs. 480 billion circular debt settlement of Jun-2013. Net lending was Rs. 342 billion.
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Circular Debt Stock
63. As per the official definition of the ECC, the circular debt stock represents the
overdue payables on CPPA-G's books. However, for the purposes of this report, the
circular debt stock includes:
i.
The amount of aggregate overdue payables to power suppliers on CPPA-G's
balance sheet; and
U. The amount picked up from CPPA-G by the Power Holding Private Limiteds
("PHPL") by funding it through Federal Government guaranteed borrowing.
64. To reduce the stock level, the following actions are proposed:
Devising a mechanism for sharing the burden of electricity subsidies and the
outstanding amount of circular debt between the centre and the provinces;
Introducing additional petroleum levy to meet the cost of circular debt. Taking
the benefit of lower international oil prices, with aggregate annual
consumption of 20 billion litres of petrol and diesel, a PKR 5 per litre charge
would generate PKR 100 billion in additional revenues per year; and
A one-time absorption of circular debt stock into the public debt, ensuring it
is linked with quantifiable KPIs and accountability mechanism whereby future
savings due to reduced cost of generation and other measures outlined in this
report are used to pay back this one-time payment.
8
PHPL was established as C special purpose vehicle managed by the Power Division and engaged in primary activity of
raising funds to finance the circular debt.
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Circular Debt Flow
65. Circular debt flow is the marginal change in outstanding stock of circular debt. It is
attributable to:
Transmission constraints;
CAPACITY PAYMENTS
67. Historically, high fuel cost was the prime reason behind expensive electricity in
Pakistan. Now, snowballing capacity payments are becoming a bigger problem.
Since FY2015, about 12,100 MW of net power generation capacities have been
added to the NTDC System while another 12,400 MW would be added by FY2025.
68. While the new power generation capacities have helped lower overall fuel cost per
unit being based on cheaper fuels than furnace oil, if we compare FY2016 with
FY2019, the increase in CPP outweighs this reduction in EPP on per unit basis in both
PKR and USD terms. The total CPP amount has in fact increased to Rs. 640 billion (Rs.
5.2/KWh) in FY2019 from Rs. 275 billion (Rs. 2.7/KWh) in FY2016.
69. Further, the front-loaded structure of ToP generation tariffs, coupled with surplus
capacity, are contributing to a higher CPP component in the power purchase price
("PPP") on a per unit basis. While the terms of the Power Purchase Agreements
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7
("PPA")
with the power producers range from 25 years (renewable) to 40 years
(nuclear power plants), their tariffs are based on debt repayments of 10-12 years.
70.
This cliff-edge structure of power producers' tariff becomes a bigger problem when
large capacity additions are crammed into a relatively short span of time, which is
the situation presently confronting Pakistan. Moreover, high interest spreads
allowed on project debts of IPPs have enabled lenders to benefit at the expense of
electricity consumers. Likewise, the LPS rates are set at KIBOR + 4.5%, while the IPPs'
borrowing costs are much lower.
No new power plants be established for the next few years with the exception
of conversion of existing wind plants to hybrid wind/solar for system stability and
to lower tariff. Plants in the pipeline should either be delayed or reconsidered,
and contracts of plants reaching expiry date should not be renewed.
Reducing the spreads over KIBOR/LIBOR for the long-term project debts.
A combination of these measures can immediately help reduce the annual CPP
burden by Rs. 150-200 billion leading to a reduction in tariff by Rs. 1/KWh.
72. Moreover, in order to utilise excess capacity, the following measures are
recommended:
Encourage KE to utilise excess capacity from the NTDC grid instead of setting
up their own 900 MW RLNG based and 700 MW coal fired plants. In order to
achieve this, investment required in NTDC's transmission system will be much
lower than the cost of setting up additional plants of 1,600 MW; and
21
c. Encourage electrification of energy use, e.g. electric vehicles, cooking, air
and water heating etc.
Therefore, there is an urgent need to review the situation in light of experience and
practices of other countries with significant hydel generation (Brazil, Canada,
China, India, etc.), and arriving at a consensus among stakeholders on a
sustainable NHP formula which the consumers and the power sector economy can
afford.
TRANSMISSION CONSTRAINTS
CPPA-G has projected that the generation on furnace oil would be about 5.2 billion
units higher in the scenario with Transmission and Distribution ("T&D") constraints than
without it in FY2020. Since fuel cost of oil-based generation is the highest of all types
of generation, this increases the aggregate fuel bill which then is passed on to
consumers as monthly fuel charges adjustment.
9 In 1986, a committee headed by Mr. A.G.N. Kazi, the then Deputy Chairman Planning Commission, was established to
propose a formula for calculation of NHP.
10 htfos://neora arg.ok/Admission%20Notices(2019/09-Seotember/CPPA -G%20Reaort%20on%2OPPP.odf
22
respectively. Besides, NTDC also requires investment in installation of grid stations
and transmission in order to overcome:
i. Network constraints at some locations
The Federal Government should facilitate NTDC in fast tracking the requisite
investment in its network to remove these constraints in order to lower the cost of
electricity.
The contractual requirements of running the 3 x 1200 RLNG based power plants at
minimum 66% annual plant factor entail a higher fuel cost of electricity. The
additional cost comes from:
With a significantly large share of cheaper and must-run guaranteed dispatch EPP
plants running on hydro, nuclear, renewable and coal, the probability of the RLNG
based plants meeting the 66% plant factor on merit order is relatively low. Further,
the ring-fenced pricing mechanism of RLNG and relatively high price of imported
LNG" make the fuel more expensive than domestic natural gas.
Due to a continued slump in international LNG market, the spot prices have
dropped to less than USD 3 per MMBTU12
for March 2020 whereas, because of these
legacy contracts, the consumers will be paying more than twice this pricen.
II Pakistan imports 800 MMCFD LNG under term contracts of which 600 MMCFD is priced at 13.37% of Brent.
12
13
hitos://wWw.lhenews.corn.okforint/611962-window-ooenslcinookistan-lc-hil u low cast
httos://osook.com/en/Droducf-and-servicesioroduct-prices/hauefied-naturul gas Ing
23
The preferred option would be price reduction as well as removal of the 66% plant
factor requirement which will yield substantial savings. However, this will require
renegotiating the terms of the LNG supply contract with Qatar. Additionally,
reducing the minimum monthly LNG supply quantities by spreading them over a
longer period will also help.
There are large variations in the price of natural gas based on its origin and category
of consumer, with the consumer price of domestic natural gas generally being
much lower than RLNG, 14 which is priced on a ring-fenced basis. In terms of
consumption however, the electricity generation sector is RLNG's biggest
consumer.
i. The supply of expensive RLNG to IPPs results in higher EPP for CPPA-G;
Hi. The supply of domestic natural gas to some inefficient GENCO units puts them
higher on the merit order than they would otherwise be if gas pricing was
uniform.
RLNG does not become part of the weighted average cost of gas ("WACOG")
because the major gas producing provinces claim it to be a violation of Article 158
of the constitution. However, gas usage and pricing are mutually exclusive and
perhaps the main reason for the Provincial opposition to combining the cost of
RLNG and domestic gas is its potentially negative impact on Gas Development
Surcharge ("GDS"). 15
"Pakistan imports 800 MMCFD of LNG under Brent linked term contracts. DES price for 600 MMCFD is 13.37% of Brent
while that for 200 MMCFD @ 11.63%.
15 GDS = Average Selling Price (local gas) - WACOG - Distribution Margin
24
Declining domestic natural gas supplies and potential imports of cheaper LNG by
the private sector would in any case constrain the provinces' future GDS revenues
and therefore, the Federal Government may consider offering minimum GDS
revenues for provinces in return for their consent for making RLNG part of WACOG.
The financing cost of the outstanding circular debt stock feeds back into an even
higher stock of circular debt. Assuming a mark-up rate of 15%, the annual financial
cost16 of the outstanding stock of Rs. 1,800 billion at Dec-2019 should work out to
nearly Rs 270 billion (around PKR 2.7/KWh based on total units billed in the CPPA-
G's record during FY2019).
However, the actual cost is less than this amount because of non-payment of mark-
up to public sector generators and periodic negotiations of LPS with IPPs.
DISTRIBUTION INEFFICIENCIES
For every 100 units of generation in NTDC system during FY 2019:
i. Around 3 units were lost during transmission; and
H. Around 17 units were lost due to T&D inefficiencies at the DISCO level.
Therefore, at the transmission and distribution level, effectively only around 80 units
were actually sold to consumers. At the billing level, the system is further burdened
with a 9% under-recovery. NEPRA allows a loss of 15 units to the DISCOs which
16
The amounts on PHPL's books carries mark-up rate of KIBOR + 80bp while the rate of Late Payment Surcharges (LPS) on
overdue payables on CPPA-G-G's books is up to KIBOR + 4%.
25
becomes part of the tariff. This means that the cost of only 2 units lost was borne by
the DISCOs themselves.
With a total PPP of Rs.1,344 billion, the total cost of the units lost works out to around
Rs. 30 billion, whereas Rs. 120 billion is lost due to under-recoveries.
The receivables of DISCOS from private sector defaulters amounted to PKR 628
billion at end of Dec-2019, comprising PKR 525 billion due from running defaulters
and PKR 103 billion recoverable from disconnected (permanent) defaulters. More
than 87% of the amount recoverable from running defaulters and around 84% from
disconnected defaulters is overdue for more than 3 years. Also worrying is the
unbridled growth in the amounts due from running defaulters who continue to
receive electricity despite non-payment. The continuing increase in these amounts
creates doubts about whether they represent disguised T&D losses (excess billing)
or genuine billing.
26
the energy sector which are leading to paradigm changes in conventional
public utility models.
handed over to the private sector while the Federal Government can continue
to retain the non-risky wire business only.
Breaking down DISCOs into smaller units: This would entail a de-merger of the
ten DISCOs into such number of companies as are suited to the needs of the
service territory in question.
Resolving QESCO issues: A cost and benefit analysis could be done with regard
1 to the provision of cheap off-grid solar power. Technical solutions based around
distributed generation and micro-grid systems should be undertaken on fast
track basis to curtail QESCO's technical losses. Further, alternative solutions
should also be explored for meeting the agricultural and domestic water needs
of Balochistan in order to reduce the reliance on tube wells.
17 Section 23E(1)
27
REGULATORY AND FISCAL REGIMES
97. The following factors, in combination, contribute significantly to the build-up of
circular debt:
98. Large cross subsidies (especially in the domestic consumer category) and heavy
tax incidence are contributing to grid defection by the industrial sector and
accelerating solarisation by others having higher electricity usage such as
commercial and high-end domestic consumers.
99. There is therefore an urgent need to simplify regulatory processes and enhance
Federal Government and NEPRA coordination with a view to limiting the circular
debt build-up on these accounts.
101. Internationally, the single buyer model has been found to create systemic risks and
allow lobby pressures to outweigh consumer interests. Similarly, in Pakistan, a failure
to transition out of this market structure has led to:
28
Financial risk of the entire Sector resting largely with the Federal
Government;
e. Tariffs which do not reflect the true cost of service provision, requiring
fl
budgetary support from the Federal Government in the shape of subsidy
injection.
In contrast, in competitive power markets, power sector service providers are profit
driven, hence the market demand and supply dynamics drive efficiency upward
and cost of service delivery downward. Further, the financial risks of the sector are
spread out over multiple participants in the market.
The structural and regulatory reform required to make this transition has historically
been resisted in Pakistan. This reluctance could be because of fear of job loss,
mistrust between the State and private investors, concerns about loss of control over
assets which provide socio-political leverage to the State, etc. and is a main reason
why the Federal Government has been largely unsuccessful in driving down the
cost of electricity.
However, in 2017, the Federal Government moved amendments to the NEPRA Act
in Parliament which were approved and notified in April 2018. A main thrust of these
amendments was the provision of a regulatory framework within which NEPRA and
r-
the Federal Government, in cooperation with the Provincial Governments, could
work towards establishment of a multi-buyer competitive electricity market in which
the government would neither be a buyer nor a seller. Details of the competitive
market related amendments are provided in section 3 of this Report, however,
broadly, these amendments envisaged the following new power market structure:
29
NTDC j ,4,Disqos
Consumer I
'Pp
Generation
Nuclear
Renews We
Under the proposed model, the physical infrastructure pertaining to the market, i.e.
transmission and distribution lines, can continue to be owned by the Government.
But since provision of a distribution and transmission service is the relatively non-risky
business of the power markets, it may actually help the Government in raising
revenues from use of its power line without worrying about collection and theft.
In order to give effect to this reform, a new section 14A was introduced in the NEPRA
Act which stipulates a:
30
108. The development of Policy and Plan in accordance with the statutory procedure is
intended to ensure holistic input and buy in of all stakeholders. Also, NEPRA is to
provide support and input in the development of the Policy and Plan and to tie in
its regulatory objectives and strategy with the approved Policy and Plan.
109. However, despite the passage of almost two years, the relevant rules and
regulations to establish the licensing framework have not been developed by the
Federal Government or NEPRA although section 50(1) of the NEPRA Act requires the
secondary legislative instruments notified before 2018 to be brought in line with the
amended NEPRA Act.18
"Such as the plan for de-licensing generation under section 14B(5) or the stakeholder consultation for developing the
National Electricity Policy or National Electricity Plan.
31
Such committee should be equipped with financial as well as technical
expertise and provided budgetary support to obtain input from local and
international experts.
c. The first proviso of section 50(1) of the NEPRA Act mandates that:
NEPRA may initiate this exercise at the earliest in order to ensure that the
requisite regulatory framework is in place.
IMPLEMENTATION PLAN
112. In order to ensure that the Federal Government can effectively execute the
recommendations given in this Report, specific action points by the relevant entity
32
have been identified. The overall responsibility to monitor progress of this plan is
recommended to be passed on to the Power Division, being the authorized arm of
the Federal Government. Within the Power Division, either the Minister-in-Charge or
Secretary Power may be assigned this responsibility and progress thereon should be
Cf reported on a regular basis to the Cabinet.
113. These recommendations are consolidated under three sections, in line with the
structure of this Report.
Cabinet Approval on
Consider retirement of CENCOs as well as IPPs recommendations of
established under the 1994 and 2002 Policy 3 Committee comprising Power Power Division
Division, NEPRA and
Ministry of Law
33
Circular Debt and Distribution Inefficiencies
Timeline
Recommendations Mechanism
(Months)
Cabinet approval of measures for one-time
Circular debt stock reduction/ elimination and reduction of finance Power Division /17hurnoe -
6 Suction with eventual payback from
cost in line with Committee's recommendations Division
measures implemented by ower Division
Debt reprofiling of public sector power plants EWAPDA, PAEC, Negotiate extension of project debt repayment
GENC0s, 4 x 1200 MW RLNG based plants!, renewable, CPEC and 3 Power Division
period to 25 years
coal-based projects
I
Reduce finance COM on long term project debts, working capital and NUM through tariff review NUM
3
LPS
34
Future Roadmap - Competitive Power Markets
Mechanism Responsibility -1
Establish an Inter-provincial committee to
finalize draft Policy for approval of CO and Immediate
draft 5-year plan for approval of Federal and ongoing Section 14A NEPRA Act Cabinet
Government
A closer look at the organogram of the Power Division shows that the current
organization structure is geared towards an entity-based structure and not function
based. This is despite the fact that different kind of specialized knowledge is
required to manage the national power policies, plans and sector, which includes
expertise in finance, law, energy economics, etc.
A restructuring plan was prepared in 2017 by the then Minister for Power,
acknowledging the need to strengthen the Division through hiring of professionals
having sound knowledge and pertinent experience by offering them market-based
compensation packages.
35
117. The proposed organogram of the 2017 restructuring plan is:
Minister
Secretory
Additional Additbonal
lectetag I leCiefaly II
L=1
Finance Special's! Regulatory Raped Managentell enlor Investment Dungy Economist Adviser (Adrriln) Media
Expert Advisor
WO110110Mter
Record Officer
(C1C)
Network
Admintshew
This organogram is structured on a functional basis, which will allow decision making
based on expert input.
Moving forward with a renewed vigor to address the issues faced by the nation's
power sector, approving this implementation plan as well as strengthening and
restructuring of MoE (Power Division) may be the most important steps in the right
direction.
36
SECTION 1 - REVIEW OF PRIVATE POWER PRODUCERS
INTRODUCTION
120. This section identifies and examines causes of the high cost of electricity in Pakistan,
especially in relation to private sector IPPs established under various power polices
issued by the Federal Government from time to time. If reviews matters pertaining
to tariff determinations, set up costs, operating costs and revenues of the IPPs, and,
consequently, quantifies the excess payments made to IPPs on account of
various causes, including oversights in tariff determination and variations in tariff
sought and tariff granted.
The overall impact under each policy has been summarized, organized according
to the fuel type used, and a way forward has been proposed. The individual IPP-
wise calculations and details are contained in Section 5.
122. There are mainly six Power Policies/frameworks under which 78 IPPs have been
commissioned with a gross capacity of 19,418 MW, details of which are tabulated
below:
Ti Table 6 - Policy Wise IPP Overviewl 9
Gross
Policy/Framework No. of ; .
Abbreviation Capacity
Projects
(MW)
Policy Framework and Package of Incenuves for Private Sector Power Generation Projects, 1994
1994 Policy 17* 6,031
Policy Framework and Package of Incentives for Private Sector Hydel Power Generation Projects in Pakistan, 1995
1995 Policy 1 84
Policy for Power Generation Projects, 2002
2002 Policy 14 3,081
Policy for Development of Renewable Energy for Power Generation, 2006
RE 2006 Policy 31 1,715
Framework for Power Co-generation 2013 (bagasse/biomass)
Framework 2013 8 254
Power Generation Policy, 2015
2015 Policy 7 8,253
78 19,418
37
123. For the above capacity of 19,418 MW, the energy mix is as follows:
Fr441:i 1, ol.1
•
"Al , En n
RFO 3,993 20.6%
Imported
3,960 20.4%
Coal
RLNG 3,633 18.8%
Gas & RFO 1,638 8.5%
Low BTU
1,637 8.4%
Gas
Wind 1,235 6.4%
Gas/RLNG 908 4.7%
Gas 789 4.1% —J
.30%
_1.20%
RFO
Imported
Coal
Id RING
vis
Low BTU Gas
am Wind
Gas/RLNG
a Gas
124. An IPP-wise detail along with sponsor and location information for the IPPs under
review, is enclosed as Annexure 1A.
38
THERMAL PLANTS - 2002 POWER POLICY
126. The 2002 Policy was amended vide ECC's decisions dated January 4, 2006 and May
22, 2006, to allow income tax exemption to dual-fuel and exclusively oil-fired power
generation projects. It was again amended vide ECC's decision dated May 23,
2007, allowing, inter-alia, the Return on Equity to be converted to equivalent US
dollars amount at reference exchange rate and adjusted for variations in USD/PKR
rates.
20
21
"PowerPolicy2002.Pdf" (http://www.ppib.goy.pk/PowerPolicy2002.pdf).
section 6, 7 and 8 of the 2002 Policy
39
Initial Review of Profitability and Dividends
The financial statements and other relevant publicly available information including
documents provided by NEPRA, PPIB and CPPA-G were reviewed for the period
starting from the CoD till June 30, 2018 or December 31, 2018 depending upon the
accounting year end of the IPP under review ("period under review").
Almost every IPP set up under the 2002 Policy reported exorbitant profits;
Large chunks of the reported profits were withdrawn in the form of dividends by
the sponsors of IPPs; and
The investment payback period for most projects was extremely short, ranging
between 1-4 years.
Star Hydro Power Ltd. - NEPRA had not finalized the CoD determination till the time
of submission of this report.
22 Since income tax exemption was available to these IPPs, a nominal amount of tax appeared in the income statements
on non-operating revenues. Therefore, for the purposes of consistency, a profit before tax figure has been used.
40
Table 10 - IPP wise detail of Profit before Tax
Mika"
`L, .
10
2010-2018
11-20
nal 2.379 2.2 14 2.052 LOSS 1.471 0.923 0.211
. 8 1.6 7 .134 .81 0.729 0.
201;5018 5.615 3.915 4.576 1.881
More Power Generation 1.668 .748 0.591 14.14
Table 11 - IPP wise detail of Dividends
Dividend in 81111cm)
Attock Gen Limited 2018 2107 2016 2015 2014 2013 2011 2011 2010
2 Liberty Power Tech Limited 2009-2018 1.995 2.993 2.993 2.993 2.993 2.494 2.245 1.497 0.499
3 2011-2018 1.009 10344 1.766 1.766 1.766 1.236
Nishat Chunian Power Limited 2010-2018 0367 1.102 2.847 2/55 3.122 1.469 0.918 0.367 -
EngrO PonlevGen QadirPur Ltd. 2010-2018 0.971 1.052 0.810 0.810 0.984 2194 Ids
Ades Power LiTnii4 0.921
6 2011-2018 2.01ra70- 1.M1 2.370 2.40 1.659
Mehra Power limited 2010-2018
7 0.708 1139 2.-11F 1.859
Sail Power Limited
2010-2018 1.411 1.372 0.966 1.159 1353 1153
S Foundation Power Company (Daharkl) Limited 2011-2018 0.917 0.898 0.898 0.905 omo 0.856
9 Sapphire Electric Company Limited
2010-2018 1.272 1,272 1.272 0.636 1.272
10 Orient Power Company Limited
2011-2018 0.833 0.833 0.625 aite 0.417
11 Uch-II Power Project
2014-2018 1.661 4.930 •
12 iialmore Power Generation Cartpany Limited 2011-20181
23 hlto://wwwpoibxgw.pUlcalit angtPdf
24 Which are denominated in Pak Rupees
41
Detailed Review of Profitability and Dividends - Methodology
A review of the NEPRA determined tariff of each IPP included internal workings of
NEPRA along with assumptions and calculation of IRR. The component-wise details
of EPP and CPP were obtained from CPPA-G. Calculations of tariff components and
their payment mechanism was also reviewed based on data provided by CPPA-G
and NEPRA. Information regarding late payment surcharge beyond 2018 was not
available.
Since the principal amount recovered through tariff is recorded as revenue in the
financial statements of IPPs, this gives an incorrect picture of the profitability of the
company. Therefore, depreciation needs to be added back and debt servicing
needs to be excluded from profit.
L-)
Beside this, various other adjustments have been made to arrive at profit generated
from operations, including:
42
Details of fuel cost were extracted from financial statements of the respective IPPs
on the assumption that raw material consumed comprised of fuel cost only.
Similarly, the Operation & Maintenance ("O&M") expenses were calculated from
the financial statements by accounting for all relevant expenses and capitalized
spares adjusted with depreciation, finance cost, etc. Finally, the fuel cost and O&M
expenses as per the financial statements were compared with the fuel cost and
O&M payments in Capacity Purchase Price and Energy Purchase Price.
which works out to Rs. 92.21 billion. After adjusting for the negative impact of
Halmore, the difference of Rs. 64.22 billion is excess/unexplained profit
("Excess
Profit" or "Excess Return").
Under the cost-plus regime, licensees are allowed the recovery of 'all
costs
prudently incurred to meet the demonstrated needs of their customers'
25 and a
'rate of return on the capital investment of each licensees commensurate to that
25
Rule 17(3)(1) of the NEPRA (Tariff Standards and Procedure) Rules, 1998
43
earned by other investments of comparable risk.' 26 Hence, given that these 12 IPPs
were given a tariff under the cost plus regime, these standards of tariffs ought to
have been applied and the allowed regulatory profit should have equaled the
adjusted profit.
141. Out of the Excess Profit, Rs. 38.96 billion has already been withdrawn in the form of
dividends. The details are given in the table below, organized in the order of highest
dividend paid in excess of allowed regulatory profit.
142. The data given in the table above formed the basis of:
The difference between the RoE allowed and RoE based on Adjusted Profit, i.e.
the annual excess RoE.
26 Rule 17(3)(ii) of the NEPRA (Tariff Standards and Procedure) Rules, 1998
44
Table 14- Detail of Average Annual Excess RoE
'
'
I
'
; I Equity Average Average • I I
Years in . Share determined Annual RoE Annual ' Average
1 operation . capita/ i as per RoE Annual
earned based
I Since 1 (Rs. in ; NEPRA on . allowed excess
Cab r Billion) ' (Ea. in based on RoE
determined
[ Billion) equity determined ' earned
'
equity
1 Attack den Limited
9 3 00 2. 49 87%
2 Liberty Power tech Limited 26% 62%
8 5.05 I 4.97 50%
3 Nisbet Chunian Limited 19% 31%
8 3.67 1 4.06 49%
4 Mahat Power Limited 20% 29%
3.54 3.91 47%
5 Uch-11Power (Pvt.) Ltd. 20% 2796
5 11.20 12.16
6 Atlas Power Limited .__ 28% 16%
7 4.74 - - 5.39 - 30%
Engro Power Gen QadirPur Limited 9
- 19% -
3.24 4.36 31%
Foundation Power Company Limited 23% - --
8 3.80 4.42 23%
9 Sapphire Electric Power Limited 18%
8 4.24 4.91 24%
10 Sail Power Limited 21%
11 9 3.86 4.69 25%
Orient Power Company Limited 22%
9 4.45 4.92 20%
12 Haltnore Power Generation Company Limited 18%
7 7.02 4.42 12% _25%
143. With the exception of Halmore Power Generation Limited, all IPPs under the 2002
Policy, which were reviewed, have earned excess profits during their operations so
far. These excess gains mainly arose under the heads of fuel cost and O&M
expense, aggregating to Rs.30.51 billion and Rs.20.4 billion,
respectively which
means that the IPPs have incurred a lower expense on account of fuel cost and
O&M expenses compared to what they have recovered through their respective
tariffs.
144. The table below, organized in the order of excess profits, depicts the excess profits
earned by each IPP including its break-up into fuel, O&M and other unidentified
factors:
Table 15 - Detail of Excess Profits From Fuel Cost and O&M Savings
Years in
Project operation Fuel 0 & 8.4 Unidentified ex
since Saving Saving saving cessive
profit
CoD
1 2011-2018 Attock Gen Limited Rs. in Billion
9 8.87 3.81 1.13
2 2611-2018 Liberty Power tech Limited 13.81
8 4.33 5.53 2.46
3 2011-2018 Nishat Clundan Limited 1232
1 8 3.02 5.01 1.27
2011-2018 Nisbet Power Limited 930
I 8 3.36 3.88 1.21
5 2014-2018 LICH.11 8.45
5 2.54 2.70 1.84
6 2011-2018 Atlas Power Limited 7.08
8 1.50 1.70 1.58
7 2010-2018 Engro PoweiGen QadirPur Limited 4.78
; 9 2.32 039
8 2011-2018 Foundation Power Company (Daharki) Limited I 0.37 3.03
9 2011-2018 Sapphire Electric Power Limited
8 (1.68) 1.37 2.08 1.77
. 8 2.29 (1.55) 0.61
10 2010-2018 Sad Power Limited 1.35
9 1.97 I (0.74)
11 2010-2018 I Orient Power Company Limited 1 0.03 1.26
o 2.00 0.74
Total 1.07
30.51 20.40 13.32 64.22
45
With reference to fuel savings, NEPRA approved 'heat rates' on the basis of
information provided by respective IPPs at the time of tariff determination. For
example, in the case of Attock Generation Limited ("AGL"), an efficiency of 45%
net Lower Heating Value (LHV) at 100% load was allowed on the basis of the
submitted life cycle heat rate curve (efficiency curve) for 25 years of the project
life.
The heat rate curve is a function of various assumptions including quality of fuel with
sludge of 2%, ageing variation and site-specific condition as detailed in Annexure
1C. According to the heat rate curve, efficiency is expected to fluctuate above
and below 45% over the life cycle of the project, while its average over the project
life is 45%. However, the analysis revealed that all RFO based IPPs, including AGL,
operated above 45% since their respective CoDs till the end of the review period.
AGL, which has the lowest capacity compared to its policy peers, has earned Rs.
8.87 billion on fuel, which contributed to almost 30% of the entire fuel saving of these
eleven plants. The supplier of fuel to AGL is also a company of the Attock Group,
which points towards possibility of transfer pricing issues that need to be further
probed.
With the exception of Foundation Power Dharki, all IPPs have saved on fuel implying
higher efficiency levels compared to the heat rate curve submitted.
If the same tariff arrangement, fuel savings and other operational factors continue
over the remaining project lives of these plants, excess profit of these eleven IPPs
over their remaining project life will be Rs.145.23 billion, resulting in total excess gains
to the tune of Rs. 209.46 billion, as tabulated below, organized in the order of
highest expected profit for the complete project life:
46
Table 16- Future Forecast of Excess Profit if Status Quo is Maintained
151. In the initial tariff decisions, RoEDC was also not allowed, in line with most
international jurisdictions (US, India, etc.). However, subsequent to the 2002 Policy,
the Federal Government issued the Guidelines in November 2005, which tilted the
incentive package in favor of private power producers:
27 h I tus://neDru.orci,DknolitUTur if Tien'LOrient%20
Power/2005MG-72%2QOPS; t.%2Plie len nitha liora24:4).1 2-0.6 20.95.4W1
47
Instead of allowing ROE, an IRR should be allowed which means RoEDC should
also be given to the sponsors;28 and
Provide mechanism for determining IRR in place of RoE: "IRR should be equal
to the long-term interest rates based on auction often-year PIB held during the
last six month plus a premium of "X" determined by NEPRA". _J
Since the tariff at that stage was already based in PKR on ten-year PlBs, this
adjustment effectively led to an incorporation of RoEDC in the tariff.
Subsequently, the ECC through its decision dated May 23, 2007, allowed PKR to
USD indexation irrespective of whether the equity invested was in local or foreign
currency. The relevant portion of the decision is reproduced as follows;
"(vii)The Return on Equity should be allowed in one currency i.e. US dollars. All
Return on Equity (for foreign exchange and rupee-based equity) be
converted to equivalent US dollars amount at reference exchange rate (as
noted in NEPRA's determination) and adjusted for variations in USD/Rs rates
as presently being done for return on foreign component of equity."29
Accordingly, based on NEPRA's interpretation of this decision, a 15% USD based IRR
was allowed for all future investment in electricity generation in the case of projects
I_j
implemented under the 2002 Policy. This USD indexation policy persisted in all
subsequent policies.
The interest rate differential between RIB rate and USD interest rate already
incorporates any impact of future depreciation of PKR against the US Dollar.
Therefore, subsequent to the decision of the ECC, the continued provision of IRR on
the basis of PKR based PIB along with USD indexation leads to duplication of
premium of PKR depreciation.
The impact of this systemic error has so far contributed to excess payments of Rs.
16.48 billion.
48
Table 17- Impact of Duplication of Currency Depreciation in RoE under 2002
Policy
lapadty 200 225 150 203 200 185 225 225
Financial Years 2011-19 2010-19 150 404 225
2010-19
Number of Years 2011-19 2011-19 2011-19 2010-19 2010-19 2010-18 2014-19 2010-18
9 10 10 9 9 9 10
k1
Overpayment w.r.LCurrency Indexation (Rs. Million)) 10 9 6 9
allowed by ECC Declaim' dated May 23, 2007
RoE 1,350 1,539 1,027 813 1,015 1,432 1,904
RoEDC 208 179 157 1226 1,045 511 1,285 13,648
225 178 180 382 417
Total 1,558 1,718 147 379 2,837
1,185 1,039 1,193 1412 2,286 2.143 658 1,664 16,985
This has led to extra earnings for the eleven IPPs of Rs. 6.46 billion
during the last 5-9
years of their operations. It is projected that these eleven IPPs will earn an additional
Rs.15.65 billion
excess RoE due to IRR miscalculation. This does not take into
consideration the impact of any future depreciation of PKR against USD. Details of
total excess payments of Rs. 22.11 billion is tabulated below.
49
MISMATCH IN DEBT REPAYMENT
NEPRA had allowed debt repayments to IPPs on a quarterly basis, however, CPPA-
G makes payment of CPP to IPPS, including debt repayments, on a monthly basis.
This mismatch between the timing of payment envisaged by NEPRA for
computation of debt service component (quarterly) versus the actual payments
made (monthly), leads to additional working capital availability for the IPPs.
It is pertinent to note that the cost of working capital is already a part of the tariff
awarded to these IPPs (except UCH-II) based on a financing cost of KIBOR + 2%.
Therefore, the impact of this timing difference for all 13 IPPs (2,934 MW) at KIBOR +
2% (KIBOR rate used for UCH-II) aggregates to Rs. 2.14 billion for the period under
review.
However, a review of the fuel inventory data for these IPPs revealed that they have
largely not maintained their fuel inventory levels, even though these IPPs were
receiving payment from CPPA-G based at predetermined fuel inventory levels.
Since AGL has a pipeline and fuel levels are not reported, the financial impact of
50
this shortfall in the remaining five RFO based plants showed extra earning of
Rs.3.63
billion.
51
IPPS SET-UP UNDER POWER GENERATION POLICY 1994
The Federal Government offered a bulk power tariff of US cents 6.5/kWh (Rs.
1.952/kWh) on average for the first 10 years while the levelized tariff worked out to US
cents 5.9/kWh (Rs. 1.776/KWh) over the life of the projects (25-30 years).
Return on Equity
The EPP was to be paid based on actual energy sold to WAPDA/KESC
and included fuel price as a pass-through item.
In terms of para 3(8) of Annexure-1 to the 1994 Policy, the tariff was designed
in a manner that if fuel cost reduced due to higher thermal efficiency
depending on the use of technology, an equivalent increase was to be
allowed in the escalable component of the CPP so that the overall tariff
remains unchanged.
The tariff offered exchange rate indexations/adjustment, fuel price variation
and adjustment due to inflation where applicable.
52
Initial Review of Profitability and Dividends
166. Out of 312 financial statements required for analysis of 1994 Policy IPPs, only 275
statements were available with SECP and NEPRA. A summary of the availability status
of the relevant financial statements is contained at
Annexure 1D. Further, in order to
determine excess profitability, the allowed RoE tariff component was needed. As
1994 Policy is silent on this, PPIB and the Power Division were requested to provide the
detailed financial model on the basis of which the upfront tariff was awarded in
1990s. However, till submission of this report, the requisite information was not
available, hence only a limited review of these IPPs could be undertaken.
167. A review of the profits and dividends from the available financial statements for the
1994 Policy Thermal IPPs showed that almost all IPPs reported enormous profits, large
chunks of which were withdrawn in the form of dividends. Recovery of equity in the
form of dividends was as high as up to 22 times the initial equity injection.
1
14 r kb P
. r 17
19
3.53
2.34
5.69
0.68 0.26
8-9 Yens
N/A
1 1.61
0.29
- 9% 1-/17
I,
1,13 ' Japan Power Gen I 0.11 2% 15/19
: 1.56 Q.62) 1 .
16 Southern Electric Power N/A (4.88)
j 20 31% M/20
20 137 (I1.5 i 033 N/A i (8.48) 014 -5014 17/20
* NOTE:
The average return has been computed based on the available financial
Ti statements. The analysis of HUB Power Company Limited could not be conducted
53
As the profitability, dividends and other details in the above table are based on less
than the actual number of financial statements, the actual profitability of companies,
in most cases, is likely to be higher than shown above.
Out of 16 IPPs, 6 IPPs have reported average annual return of more than 60% and
four IPPs have earned an annual return of around 40%. The Committee is of the view
that the matter of excess returns in 1994 needs to be examined in further detail after
provision of information pertaining to allowed return on equity by the Ministry of
Energy (Power Division).
It covered not only private and public sector power projects, but also projects
based on public-private partnership and projects developed by the public
sector with the intention of subsequent divestment.
It envisaged a two-part, USD indexed tariff comprising of CPP and EPP. The Policy
identified EPP to be based on units delivered while CPP was determined to be
payable provided the plant was made available for dispatch as per the
standards defined in the PPA.
54
mitigate the exchange rate variation risk, specified adjustments for exchange
rate variations were also provided within the Policy.
The PPIB and relevant public sector departments in provinces, Azad Jammu &
Kashmir ("AJK") and Gilgit Baltistan ("GB") were mandated to implement the
policy by providing a one-window facility to prospective project sponsors.
172. The energy mix which was set-up under the 2015 policy is as follows:
173. The following companies have achieved CoD under the 2015 Policy:
55
Table 24- IPPs under the 2015 Policy
{
1 Huaneng Shandong Ruyi (Pak) Energy Pvt. Ltd. 1320 Imported coal 28.102017
2 Port Qasim Electric Power Company Pvt. Ltd. 1320 Imported coal 25.4.2018
3 China Power Hub Generation Company Pvt. Ltd. 1320 Imported coal 19.9.2019
National Power Parka Management Company 1230 RLNG 29.7.2018
4
Pvt. Ltd. (Haveli Bahadur Shah Power Project)
5 Quaid-e-Azam Thermal Power Pvt. Ltd. 1180 RLNG 20.5.2018
National Power Parks Management Company 1223 RLNG 29.7.2018
6
Pvt. Ltd. (Ballolci Power Project)
7 Engro Powergen Thar (Private) Limfted 660 Local coal 10.7.2019
Total 8,253
In case of China Power Hub Generation Company and Engro Powergen Thar
(Private) Limited, the CoD adjusted determination of tariffs have not been issued by
NEPRA till the time of preparation of this report.
Further, two out of three RLNG based projects, namely Haveli Bahadur Shah Power
Project and Balloki Power Project, are owned by Federal Government, whereas
Quaid-e-Azam Thermal Power Pvt. Ltd. (Bhikki) is owned by the Government of
Punjab.
Therefore, analysis of the two imported coal-based power projects namely Huaneng
Shandong Ruyi (Pak) Energy - Sahiwal ("HSR") and Port Qasim Electric Power
Company ("PQEPCL") was undertaken.
56
Table 26 - NEPRA Determined Project Cost for Imported Coal
te.b±Ril'AV :1•7P - 660MW 1099MW
rinirifill pi; L. Fin. F. Fin.
Fin.
US!) in million
Capital Cost 271.8 271.8 455.0 455.0 767.9 767.9 1,191.7 1,191.7
Custom Duties & Cess 10 8 10.8 18.1 itt 30.5 30.5 47.3 47.3
Sub-Total 282.6 282-6 473.0 473.0 798.4 7984 1,239.0 1,239.0
Financial Charges:
Financing Fees & Charges 7.4 7.4 12.4 12.4 21.0 21.0 32.5 32.5
&no sure Fee 22.2 - 37.1 63.9 - 99.2
IDC 19.3 67.0 32.2 112.1 72.8 261.6 113.0 405.9
Sub-Total 45.8 74.4 81.7 124.5 157.7 282.5 244.7 438.5
o WWU .0 tiaiii.initihailk, 'SOS
Due to the budget request for hiring international consultants not being approved, it
was not possible to undertake third-party comparisons between actual project costs
reported by these projects and project costs established internationally for similar
technologies. Alternatively, various components of tariff were reviewed with the
objective of ascertaining their reasonableness and basis of calculation.
The total project costs of the two IPPs as determined by NEPRA were compared with
the project cost capitalized in their financial statements.
r--
Overview of Findings
EXCESS ALLOWANCE OF RS. 32.46 BILLION ON ACCOUNT OF SET-UP COST
A comparison of the total project cost of the two IPPs as determined by NEPRA versus
the amounts reported in their financial statements showed that excess project cost
was allowed to the two IPPs to the tune of Rs. 32.46 billion with the following
breakdown:
57
Table 27- Excess Setup Cost allowed to IPPs under 2015 Policy
182. The main component of this excess cost was the financing cost including IDC. In the
case of HSR, at the time of CoD, the IPP had requested an IDC of USD 197.34 million.
However, NEPRA allowed IDC of Rs. 17.56 billion (USD 167.91 million), whereas as per
the financial statements of HSR, the IPP actually incurred an IDC of Rs. 6.71 billion,
leading to an excess allowance of Rs. 10.85 billion in set-up costs (USD 103.77 million
at CoD exchange rate).
183. Similarly, PQEPCL was allowed Rs. 24.84 billion (USD 234.91 million) in finance cost
(including IDC, Sinosure fee, lenders fee, etc.) whereas it actually incurred Rs. 12.53
billion (USD 112.79 million) on this account giving rise to an excess allowance of Rs.
12.31 billion (USD 122.13 million) in set-up cost. The aforementioned excess
allowances were due to the following reasons:
185. Based on this adjusted equity amount, HSR was entitled to USD 70.90 million per year
as RoE, however, HSR has been allowed USD 98.30 million by NEPRA, meaning an
excess of USD 27.40 million in annual return payments will be made to HSR over the
project life of 30 years.
58
186. Since the project has recently started and the RoE is indexed with USD, assuming that
USD appreciates against PKR at an average rate of 6% per annum, the excess
payment on this account aggregates to a total of Rs. 291.04 bilion
over the next 30
years.
7 187. In case of PQEPCL. NEPRA corrected the error of construction period and assumed
actual construction period to compute return during the construction period.
This excess 1.39% IRR translates to around Rs. 1 billion per year extra payment to each
IPP at the current USD/PKR Exchange rate. Assuming that USD appreciates against
PKR at an average rate of 6% per annum, the excess payment on account of IRR
would amount to Rs. 72.5 billion in case of HSR and Rs. 87.6 billion
in case of PQEPCL,
aggregating to Rs. 160.14 billion over the entire project life of these two IPPs.
Expected overpayment to RLNG plants, which are in the public sector will also need
to be rectified by NEPRA before their privatization.
Since the projects under 2015 Policy have recently achieved CoD and major debt
repayments will be made in the future, due to unknown assumption, it was not
possible to project the future impact of this mismatch.
59
2015 POLICY - IPP-WISE SUMMARY OF EXCESS PAYMENTS
193. A summary of the IPP-wise excess earnings is tabulated below.
Solar photovoltaic (PV) and thermal energy for power generation; and
All other RE technologies were excluded from this policy. The policy recognized a
minimum 9,700 MW as the medium-term target for deployment of renewable energy
("RE") technologies by the year 203032.
60
Build, Own, Operate and Transfer ("BOOT") models which shall be valid for a period
( of not less than 20 years.
197. The policy envisaged a tariff based on per-unit rate (Rs./KWh) as the policy
acknowledged it is difficult for RE IPPs to guarantee capacity availability. Further, in
the case of hydro projects, a water use charge of Rs. 0.15/kWh was also fixed within
the 2006 Policy, which was to be paid by the IPP to the provincial/AJK/Northern Area
governments.
198. The risk of variability of wind speed and water flow was envisaged to be borne by the
I--
1
power purchaser. It was conceived that for each project location identified under
the policy, benchmark electricity production levels based on mean availability of
wind and water flow on monthly basis were to be determined and revenues
— corresponding to this benchmark were ensured to the IPPs provided that reduction
1
in electricity production was not due to the IPP's fault.
200. Other incentives included exemption from income tax, repatriation of equity and
dividends, and provision to raise local and foreign financing.
202. Details of the various tariff regimes are given in Annexure 1E.
61
METHODOLOGY FOR DETAILED REVIEW OF WIND POWER PROJECTS
203. A review of NEPRA's tariff shows that the tariff component is based on Energy Based
Tariff ("EBT"), which includes debt repayment and return on equity (IRR based return).
204. The profitability and dividends of seven IPPs, with operational record of more than
three years, was analyzed. As discussed above, the returns of seven IPPs were
adjusted to arrive at an Adjusted Profit generated from operations which was then
compared with the allowed RoE.
Years in Profit
operadon Share
Name of Wind Power IPPs Capacity (since before
Capital
MW tax
CoD)
Rs. in billion
1 FTC Energy Limited 49.5 2.44 4.21 0.80 29%
2 Sapphire Wind Power Company Ltd. 52.8 4 326 3.74 0.73 29%
3 Three Goes First Wind Farm Ltd. 49.5 4 2.55 3.59 28%
4 Hydro China Dawood Power Pvt. Ltd. 49.5 4 3.47 2.80 0.88 27%
5 Foundation Wind Faergy-IE Pvt Ltd. 50 5 3.53 4.13 0.35 23%
6 Foundation Wind Enerty-I Pvt. Ltd 50 5 3.50 4.05 0.15 23%
7 Zorlu Energy Pakistan Ltd 56.4 6 2.92 3.47 20%
206. The Wind IPPs earned an average annual °crusted RoE ranging between 14-21%.
1 Foundation Wind Enagy-11Pvt Ltd. 5 333 4.13 3.74 3.60 0.135 21% 20%
2 Sapphire Wind Power Company Ltd. 4 326 3.74 2.74 2.68 0.056 21% 21%
3 Zodu energy Pakistan Ltd. 6 2.92 147 143 4.62 (1.192) 20% 26%
4 Three Gorges First Wind Farm Ltd 5 2.55 3.59 2.49 2.48 0.014 20% 19%
6 Foundadon Wind Energy-I Pvt. Ltd. S 330 4.05 107 2.93 0.145 18% 17%
7 Hydra China Dawaod Poore: Pvt Ltd. 4 3.47 2.80 1.46 1.82 4367) 14% 18%
62
As evident there is minimal difference between the annual return earned based on
adjusted profit and the RoE allowed as per tariff of these IPPs. However, the following
paragraphs detail anomalies identified in the tariff determinations of these IPPs which
require immediate rectification.
EXCESS GENERATION
Under the Wind Upfront tariffs of 2013 and 2015, the power producer ought to have
recovered the entire cost of debt, interest, O&M, insurance and 17% USD IRR,
provided they operate the plant at the minimum benchmark (31% under 2013 tariff
and 35% under 2015 tariff).
Any energy generated in excess of the minimum benchmark leads to additional tariff
payments in a pre-determined ratio which includes debt and interest components.
Therefore, with respect to production over and above the minimum benchmark, the
IPP will be able to recover debt and interest (beside O&M and RoE) over and above
the amount that actually has to be paid to the lenders.
When, on a sample basis, the annual Net Electrical Output was compared with the
benchmark energy based on an annual plant capacity factor, the actual power
generation has not meaningfully exceeded the minimum benchmark during the
operational period under review.
Although this has not resulted in any excess payments so far, this tariff determination
methodology could be problematic in the future since any payment above the
production benchmark will effectively translate into excess payment because the
debt and interest components are already fully recoverable in the fixed costs
guaranteed up to the production benchmark.
Due to the mismatch between annual payments envisaged by NEPRA of USD based
17% IRR versus the monthly payments made by CPPA-G, the actual IRR earned by
these IPPs works out to be higher than the IRR allowed by NEPRA.
The Wind IPPs under review have therefore been incorrectly allowed 18.39% return
instead of 17% return. This has led to excess payment of Rs.1.58 billion
during the
63
period under review. These seven IPPs will earn additional Rs.4.75 billion excess return
on equity till the end of their respective contract periods on account of this timing
mismatch leading to total excess payment of Rs.6.32 billion.
This Rs. 6.32 billion excess payment on account of miscalculation in IRR over the
project life of 20 years to seven IPPs having 357.7 MW means excess earning of Rs.
17.67 million per MW. If projected for all operational wind IPPs (1,233.5 MW), this works
out to excess RoE of Rs. 21.8 billon, excluding the impact of future depreciation of
PKR, over the project life of 20 years.
As discussed in detail under the section on 2002 Policy IPPs, the mismatch between
the timing of debt payment envisaged by NEPRA for computation of debt service
component (quarterly) versus the actual payments made by CPPA-G (monthly)
leads to additional working capital availability for the IPPs which eventually leads to
additional profitability.
64
•••••
While reviewing the tariff determination in the case of Zorlu Enerji Pakistan Limited,
misrepresentation in setup cost was observed. Zorlu filed a motion for leave for review,
along-with relevant documentary evidence against NEPRA's decision in the matter
of its COD tariff adjustment.
The profitability and dividend of four IPPs, which have operational record of at least
three years were analyzed. As discussed earlier, their returns were adjusted to arrive
65
at an Adjusted Profit generated from operations in line with the review methodology,
which was then compared with the allowed RoE.
224. The Solar IPPs earned average adjusted annual RoE ranging between 12-16%.
QA Solar Power Pvt. Ltd 4 3.81 5.39 1.86 3.77 (1.906) 12% 25%
1
Apollo Solar Development Pakistan 3 3.45 2.58 1.52 1.81 (0.283) 15% 17%
2 Ltd.
Crest Energy Pakistan Ltd 3 3.83 1.89 1.89 1.94 (0.051) 16% 17%
3
4 Best Green Energy Paldstan Ltd 3 3.23 1.38 1.41 1.56 (0.148) 15% 16%
Total 11.24 6.69 9.07 (2.388)
225. As evident there is minimal difference between the annual return earned based on
adjusted profit and the RoE allowed as per tariff of these IPPs. However, the following
paragraphs detail anomalies identified in the tariff determinations of these IPPs which
require immediate rectification.
1
66 .H
EXCESS GENERATION
226. Under the solar tariff regimes, the power producer ought to have recovered the
entire cost of debt interest, O&M, insurance and RoE provided they operate the
plant at the minimum benchmark. Any energy generated in excess of the minimum
benchmark leads to additional tariff payments in a pre-determined ratio. Payment
of the debt and interest components is already accounted for at the net annual
capacity factor. Therefore, if the IPP operates in case of excess generation, it will be
able to recover debt and interest over and above the amount that is actually
payable to the lenders.
When, on a sample basis, the annual Net Electrical Output was compared with the
benchmark energy based on an annual plant capacity factor, the actual power
r- generation has not meaningfully exceeded the minimum benchmark during the
operational period under review.
Although this has not resulted in any excess payments so far, going forward, this tariff
determination methodology could be problematic since any payment above the
production benchmark will effectively translate into excess payment because the
debt and interest components are already fully recoverable in the fixed costs
guaranteed up to the production benchmark.
NEPRA has allowed a dollar-based equity IRR of 17% assuming annual payment of
return, whereas actual payments of RoE is made to IPPs on a monthly basis by CPPA-
G. Consequently, the Solar IPPs earned a higher RoE of 18.39% compared to the
allowed return of 17%. In monetary terms, the 4 Solar IPPs have earned an extra return
of Rs.0.69 billion during the period under review and will earn an additional Rs.4.48
billion till the end of their respective contract periods on account of this timing
mismatch.
In total, Rs.5.17 billion will be earned during the entire life of the project due to this
error, as detailed in the following table:
67
Table 36- Projected Excess Return over Life of Solar IPPs
. ' IRR 7
IRE IRR
Allowed miscalculadort4-
Years in Return on miscalculation miscalculation
Project RefUfn on for the endte
operation Equity paid from COD till in rest of project .
Equity project Ilte
ill ,
2018 life
ye
Rs. in Billion
1 QA Solar Power Pvt. Limited 4 3.48 3.76 0.28 1.47 1.75
Apollo Solar Development Mist= IR 0.14 1.03 1.17
3 1.66
limited
3 Crest Energy Pakistan Limited 3 1.79 1.94 0.15 1.10 125
4 Best Green Batty Paldstan Limited 3 1.43 1.55 0.12 0.88 1.00
As discussed in detail under the section on 2002 Policy IPPs, the mismatch between
the timing of debt payment envisaged by NEPRA for computation of debt service
component (quarterly) versus the actual payments made by CPPA-G (monthly)
leads to additional working capital availability for the IPPs which eventually leads to
additional profitability.
Like wind-based IPPs, it is not possible to reasonably estimate the impact of this
mismatch due to unavailability of various assumptions. However, it needs to be
rectified by NEPRA and CPPA-G as it has the potential to have a significant impact
on the future payments.
68
The Power Purchaser was required to mandatorily evacuate all energy offered by
the Power Producers, failing which the plants shall be deemed to have been
dispatched and energy sold to the Power Purchaser. The entire range of financial
and fiscal incentives available to the RE projects under the RE Policy of 2006 were
also made applicable to all the projects implemented under the said Framework.
1 - 10 years 11.7396
it -3o years 7.9147
The following 8 projects have achieved CoD under this tariff regime:
The tariff assumed an Annual Plant Capacity Factor ("APCF") of 45% on the basis
of 180 days and plant availability of 92% for Co-generation projects. NEPRA had
originally assumed a 50% APCF. However, Pakistan Sugar Mills Association
("PSMA") in its presentation to NEPRA in the hearing objected that 50% APCF as
proposed by the Authority was not achievable based on the period of sugar
cane crushing season and bagasse availability to the sugar mills during off season
for power generation. PSMA submitted that actual crushing season in our country
lasts for 100-110 days, therefore, adjusting for shorter crushing season in our
69
country, the realistic APCF for Co-generation projects works out to be around 40%
which may be considered by the Authority. Examples of neighboring country was
provided where regulator has fixed APCF of 45% based on 180 days (120 days
crushing season and 60 days off season). Accordingly, NEPRA granted raise in the
base tariff due to change in APCF from 50% to 45%.
ii. Based on the APCF of 45%, annual energy of a capacity of 1 MW (91.5% net
capacity after auxiliary load) arrives at 3.607 GWh (IMW x 91.5% x 45% x 365 days
x 24 hours), which was used by NEPRA in the calculation of fixed cost
components, RoE and debt service cost when determining the tariff.
The financial statements of these IPPs were reviewed and, as discussed earlier, their
returns were adjusted to arrive at an Adjusted Profit generated from operations in line
with the review methodology, which was then compared with the allowed RoE.
In the case of JDW Sugar Mills Limited and RYK Mills Limited, the main business of the
companies was other than power generation, therefore, all required information
pertaining to power generation was not available in their financial statements.
Further, in case of Chiniot Power Limited, financial statements for only the first tWo
years were available, consequently it was not possible to analyze the financial
statements in detail.
However, the collective Adjusted Profit pertaining to projects JDW-II and JDW-III
("JDW") were determined by using information reported in the Group Reportable
70
Segment under the head "CO-Generation segment"
in the consolidated financial
statements of JDW Sugar Mills Limited.
243. A comparison of the Adjusted Profit with the allowed RoE as per the information
provided by CPPA-G showed that there were material excess profits made by JDW.
7
The reasonableness of tariff determination was also reviewed to identify the causes
of these excess profits. In this regard, the assumption of plant factor of 45% used in
the tariff determination was corroborated with the actual plant utilization (annual Net
Electrical Output) as per the information provided by CPPA-G. A similar comparison
was also conducted for RYK Sugar Mills Limited Bagasse Power Plant and Chiniot
Power Limited.
The company wise detailed reports along with respective findings are contained
after the implementation plan provided in this report, however, summarized
observations are contained in the following paragraphs.
NEPRA had allowed a return to the Bagasse IPPs based on 15% USD Equity IRR to be
paid annually. In reality, the IPPs are paid their CPP on a monthly basis by CPPA-G,
which includes RoE. Because of this mismatch between the timing of payment for
computation of IRR, the IRR earned by these IPPs is higher than the IRR allowed by
NEPRA, i.e. 18.39% return instead of the allowed 17% return.
In monetary terms, this works out to extra earning for the IPPs of Rs. 0.26 billion
during
the last 3-5 years of their operations, i.e. the period under review. It is projected that
these four IPPs will earn an additional Rs.4.62 billion
by the end of their respective
contract periods as excess RoE, assuming that USD appreciates against PKR at an
average rate of 6% per annum.
71
Table 40- Excess Profitability: IRR Miscalculation
The Bagasse power plants under review were producing electricity in excess of the
plant factor used by NEPRA for tariff determination. Payment of fixed costs, i.e. fixed
O&M - local, working capital, insurance, etc., as well as debt service cost is linked
with the plant factor which was determined at 45% in the tariff determination.
The electricity generation in excess of 45% plant factor therefore leads to excess
payment on account of fixed cost and debt service cost, which is included as a
revenue of the IPPs, resulting in excess profits.
Since the IPPs under review have produced electricity in excess of 45% plant factor,
excess gains were made by the IPPs, details of which are tabulated below:
'.P?,0,V71.4k444:1417t
JDW-I1 5 2.05'
JDW Sugar Mills limited
IDW-111 5 1.94
RYK Mills Limited RYK Sugar Mills Limited Bagasse Power Plant 3 1.0
Chiniot Power Limited Chiniot Power limited 3 1.34
Total 6.33
It may be noted that the CPPA-G has taken notice of this issue and during 2018,
CPPA-G has initiated adjusting/deducting the excess payments made to these four
projects. However, the IPPs have challenged the action of CPPA-G in the Islamabad
High Court and are claiming that excess gain on account of plant factor is their right.
The Honorable Court has referred the case to Secretary, Power Division and a
decision in the matter was still pending at the time of submission of this report.
72
WAY FORWARD - PRIVATE POWER PRODUCERS
252, The exorbitant returns earned by IPPs as detailed in the preceding paragraphs, are
generally attributable to:
Misinformation by IPPs
253. Successive Federal Government policies offered incentives and exorbitant returns
leading to significant private investment in the power sector. The fallout of this was:
Excess Overcapacity
generation coupled with
capacity Power tariffs
the 'take or raised
added pay' provisions
254. With the advent of cheap renewables and RLNG spot prices lower than USD
3.00/MMBTU, these industries are finding their own cost-effective solutions and
becoming less reliant on the grid to support their power needs. If this trend continues,
it will force the most profitable consumers out of the system and increase the power
cost to remaining consumers. The power sector in its existing setup is economically
unsustainable for Pakistan.
255. The Committee, therefore, suggests four major interventions to address issues
pertaining to excess profits and reduce power tariffs for the benefit of the consumers
and the economy:
73
Recovery of Past Excess Profits Paid
256. Under the 2002 Policy, projects were to be processed either through:
levelized tariff; or
257. In the latter case, the tariff was to be awarded under the NEPRA (Tariff Standards and
Procedure) Rules, 1998, rule 17(3) of which requires NEPRA to allow "...licensees the
recovery of any and all costs prudently incurred to meet the demonstrated needs of
their customers" and "...a rate of return on the capital investment of each licensees
commensurate to that earned by other investments of comparable risk". This
stipulates a cost-plus regime for grant of power sector tariffs, under which NEPRA is to
assess the prudent cost through a process of stakeholder consultation. This prudent
cost includes a market-based return on the licensee's investment.
258. Under this tariff structure, the performance of IPPs post-CoD should have been
regularly monitored to revisit the basis of tariff and its reasonableness of underlying
assumptions. Failing this, excess payments were made in two broad categories:
2002: Difference between their allowed and actual fuel cost and O&M.
2006: Extra profits because of initial misreporting of annual plant capacity
factor of bagasse-based plants and misrepresentation of set-up cost in
one wind-based plant.
2015: Difference between set up cost claimed, and actual cost incurred.
This has also led to computation of excess profit payment over the project
life in one plant.
b. Systemic errors in tariff determination and tariff component payment
frequency, i.e.:
74
ADDRESSING MISREPRESENTATION ISSUES
2002 POLICY
This amount of Rs. 64.22 billion should be recovered from the IPPs since the tariff was
awarded under a cost-plus regime where an IPP is only entitled to a regulatory return
and no justification has been identified in the tariff documentation allowing the IPPs
to receive an excess payment on account of fuel, O&M and other factors. This should
be adjusted against the outstanding dues of each IPP parked in CPPA-G's books.
The
legal perspective will be explained in the later section.
Regarding sharing mechanism for energy generation beyond net annual capacity
factor whereby an IPP can recover extra fixed costs including debt servicing resulting
in profitability beyond what is envisaged under the tariffs, only the RoE component
along with key elements of fixed O&M should have been made a part of the tariff. It
is therefore recommended that
the sharing mechanism be reviewed and only the
RoE component along with fixed O&M should be allowed
on marginal generation
beyond allowed net capacity
factors in all existing upfront determinations as well as
in all future determinations.
The excess profits recorded by 4 bagasse based IPPs are on account of misreporting
by the Pakistan Sugar Mills Association regarding Annual Plant Capacity Factor. The
recovery of fixed cost and debt servicing should have been restricted to the
determined plant factor of 45% instead of actual energy generation. Fixed cost and
debt servicing as a component of payments made for generation above the 45%
benchmark are essentially excess gains, which should be recovered,
and corrective
measures should be taken by NEPRA to address this issue in future.
75
2015 POLICY
263. Excess payment to IPPs under the 2015 Policy related to setup cost, totaling Rs. 32.46
billion:
264. The difference in setup cost allowed versus reported setup cost is mainly because of:
265. Further, in the case of HSR, NEPRA allowed a return component on 48 months
construction period as against the actual construction period of 27 months at the
time of HSR's CoD. Combined with extra setup cost, this increased the return payment
by about USD 27.40 million per year (from USD 70.90 million per year to USD 98.30
million per year).
266. If status quo is maintained, HSR and PQEPCL will collectively earn Rs. 2,083.82 billion
RoE over their remaining concession periods, out of which at least Rs. 291.04 billion is
on account of allowance of the excess project cost.
The CoD tariff review petitions of these two companies are currently pending before
NEPRA and no decision has yet been made by NEPRA till submission of this report.
76
Rs. 32.46
billion be deducted from the project cost of PQEPCL and HSI?:
The return payment formula be corrected
to reflect actual construction time;
and
This will also set a benchmark for COD adjustments of all coal-based power plants,
whether on Thar or imported coal, which are soon to be commissioned, and
accordingly going to apply for CoD tariff adjustment before NEPRA.
SYSTEMIC ISSUES
OVERSIGHT IN IRR CALCULATION
270. Certain tariff anomalies were noted in the tariff of all IPPs. One of these related to
computation of IRR on an annual basis by NEPRA whereas the payments to IPPs are
made on a monthly basis.
With respect to the oversight in IRR calculation, a total of Rs. 11.63 billion was
overpaid, i.e.:
r—r
6.46 billion to
Rs. 1.58 billion to Rs. 0.69 billion to Rs. 2.64 billion to
1.3 IPPs under Rs. 0.26 billion lo 2 coal based
2002 Policy 7 Wind IPPs 4 Bagasse IPPs 4 solar IPPs under
2006 Policy IPPs under 201 5
Policy
77
Payment made on this account should be recovered and this error may be rectified
in all future tariff determinations/payments.
As discussed above in detail, the determination of IRR on the basis of PIBs, when
indexed to USD/PKR parity vide amendment in 2007, is in fact duplication of premium
for depreciation of PKR against USD.
The impact of this systemic error has so far contributed to excess payments of Rs.
16.48 billion to 11 IPPs under the aforesaid Policy. The issue of double counting also
exists in other IPPs established under various policies, however, the impact has not
been calculated due to lack of relevant information. The Committee is of the view
that the excess amount should be recovered and for future, reference be made to
the recommendation given in sub-section "Switch from USD to PKR Based Return"
below.
78
landscape of technology which may lead to inaccurate forecasting of CAPEX and
OPEX assessment by NEPRA.
281. This mechanism is also prescribed in neighboring India, where savings in EPP are
shared between the plant owners and end consumers34
. It protects consumers in
case of excess gains obtained through misinformation, deceit or fraud. Unfortunately,
no such mechanism was prescribed for any of the IPPs in Pakistan and there is an
r-
immediate need to prescribe a sharing mechanism of excess profits for the entire
generating sector going forward.
•
282. For clawback to be introduced, it needs to be ensured that:
0
Setup costs are approved after extensive due
dirigence
1111
,
Efficienciescre determined through heat rates test
conducted under international best practices
These steps may lead to a tariff truly reflective of cost/expense with a reasonable rate
of return being given to compensate the investment. If an IPP lowers expense and
improves its performance benchmark, any resulting benefit in profit ought to be
shared with consumers. This way an IPP will be encouraged to be more efficient.
It is important to note that the question of claw back being applied retrospectively
does not arise with respect to the reasons highlighted above. Instead past payments
are proposed to be fully recovered in outstanding payments or future payments to
IPPs. In future, as a matter of policy,
claw back mechanisms are recommended to
be Introduced whereby extra profit made by an
IPP for improved efficiency is shared
with the consumers in a certain pre-determined ratio.
Such clawback mechanism will
be possible when existing tariffs are reduced to levels reflective of the true and
prudent cost of operations of generating companies.
34 bjlilLtgr_citAggiai9 rantsciti_gauw......
79
285. Going forward, the minimum level of required disclosures should be demanded by
_J
NEPRA. This should include:
Expense side: Breakdown of raw material consumed into fuel and lubricants,
variable and fixed O&M - foreign and local components, comprehensive details
of fuel inventory such as opening stock, addition, closing stock in quantity and
in amount, capital expenditure incurred on major overhauls, capital spares, etc.
It is also worth mentioning that coal-based plants under Power Policy 2015 have been
given USD IRR as high as 20%, which translates to a USD RoE of 34.49% . The USD ROE
'of 34.49%35 was given when reference PKR to USD rate was 97.1. If the current rate
of 155 is assumed, a USD RoE of 34.49% translates to about 55% PKR RoE.
The returns being offered to different technology power plants which are currently
operational at national grid are tabulated as follows36:
Bagasse
Renewable
Solstr/Wincl
H die
80
289. To understand the benefit of switching to guaranteed returns in local currency, the
following comparison was developed for 11 IPPs under the 2002 Policy and 2 IPPs
under the 2015 Policy:
Return fixed at USD/PKR exchange rate level of June 30, 2019: No further
indexation allowed beyond this date till the expiry of concession agreement;
and
Return fixed at USD/PKR exchange rate at the level of the first complete year
after COD: No indexation allowed beyond this date till the expiry of
concession period.
Since coal plants are recently commissioned, options B & C for coal plants will
remain the same.
RoE to be Rernainbig
Project Return paid Return
Remaining Equity Return Return at
Life Already during Total Total Pint year Return for
Life Injected Already 06/19 thee CoD Total
Allowed Remaning Retwn Return Remaining
Allowed USD/PKR IJSD/PER Return
life Life
puny parity
37
It may be argued that 6% annual depreciation of PKR is high for the estimate, however, at the time of the 1994 Policy,
USD 1 was equivalent to PKR 30.03, which, with current rate of PKR 155/USD I translates too Compound Annual Growth
Rate of 6.5% during the last 26 years.
81
In scenario A, which assumes continuation of returns being indexed to USD, the 2002
Policy IPPs will profit of Rs. 511.03 billion for the remaining terms of the contract for a
combined invested equity of Rs. 50.79 billion, whereas the two plants under 2015
Policy will receive a whopping Rs. 2,083.82 billion profit payment during the remaining
28/29 years of operation against their combined equity of Rs. 83.01 billion. We have
seen similar profitability numbers in 1994 and 2002 Policies.
In scenario B, where returns are fixed at the level of June 30, 2019 USD/PKR exchange
rate, IPPs under the 2002 Policy will get a return payment for the remaining term of
the contracts of Rs. 326.42 billion instead of Rs. 511.03 billion. In scenario C, if the 2002
IPPs return was fixed in PKR based on USD/PKR exchange rate of first year after COD
without any USD indexation, the future payment of return will be Rs. 178.31 billion.
For the two coal projects, against their total investment of Rs. 83.01 billion, the
payment of return can be reduced to Rs. 787.27 billion Instead of Rs. 2,083.82 billion if
the USD/PKR exchange rate is fixed at June 30, 2019 parity. Even after this, the two
coal projects will still receive, on average, RoE of 33.24% per annum.
under the current formula, in two years of operation, HSR has already recovered
71.18% of its original equity invested whereas PQEPCL has recovered 32.46% of its
original equity in the first year of operation. These are just two plants under the 2015
policy and more than 6000 MW will join the system at a higher percentage of return.
The Committee estimated the impact of switch from USD to PKR based return for the
whole sector excluding 1994 plants (13,154 MW). The Government would have to pay
Rs. 7,992 billion over the remaining lives of these plants in case USD indexation is
continued compared to Rs. 3,266 billion if it switches to PKR based return fixing the
PKR/USD parity to first year after CoD, leading to saving of more than Rs. 4,700 billion.
This amount will increase substantially due to capacity additions in the future.
82
Table 45 - Savings: Switching from USD to PKR based Returns
Rs. In billion
2002 (2,93436W)
595.43 252.19
2015 (3,253 MW)
6,514.31 2,547,39
2 coal (2,640 MW)
2,083.82 814.87
Huh • Engro thar (1,980 MW) 1,562.87 611.15
RLNG (3,633 MW)
2,867.62 1,121.37
RE 2006
! Wind (1,233 MW)
619.26 336.69
1 Solar (480 MW)
190.86 86.97
Bagasse (254 MW)
73.08 43.14
1 . 7,992.94 3,266.38
It is therefore abundantly clear that the existing system of offering returns indexed
with USD is not sustainable.
It is important to highlight that in neighboring India, return
offered is 16% in Indian Rupees.
which is 27% of the approved invested equity. This practice should therefore be
discontinued in the interest of the consumers and a simple RoE should be allowed
without incorporating RoEDC.
83
In Pakistan, successive power generation policies have reinforced the requirement
of a ToP based arrangement wherein capacity payments were to be made to the
IPPs, provided they were available for dispatch, regardless of the actual power
purchased by the Federal Government. Such contracts are designed to suit project
lenders who have committed to majority of the project cost with limited recourse.
Further, ToP provisions extend over the life of the project, i.e. 25-30 years, which is
much longer than the debt repayment period, being around 10 years in Pakistan.
Therefore, despite full repayment of their debt, investors continue to get the
guaranteed return based on ToP contracts for years 11-25 or 11-30 depending on the
terms of the contract. Since these projects are set on BOO basis instead of BOOT
basis, payment of guaranteed returns under the ToP arrangement for 25-30 years,
instead of only the first few years which may be sufficient to compensate the
investors, is completely unjustified and contrary to consumer interest.
Shifting to TaP based contracts will address the accumulation of capacity payments
as well as enable the move to a competitive power market structure, as explained in
Section 3 of this Report.
Since long-term debts have not been fully paid for every IPP, the following strategy is
recommended to shift all IPPs to TaP contracts.
2015 POLICY
The majority of projects implemented under the 2015 Policy have recently
commenced operations, therefore, their long-term debts are still outstanding. In fact,
the repayment of debt has been allowed in a relatively short period of 10-12 years.
These front-loaded tariffs are going to increase the capacity payment obligation of
the Federal Government, therefore, as a matter of policy, negotiation should be
started with these IPPs for debt rescheduling to 20-25 years instead of the current 10
to 12-year arrangement.
This would flatten the prevailing front-loaded tariff structure, thereby reducing the
immediate financial burden of end-consumers. In order to move these plants towards
a TaP structure, the following steps are recommended:
84
IPPs to After 10
reschedule Guaranteed years, TaP Only the
their debt return to be provisions
repayment r restricted to should
debt
component
period to 20- 10 years replace to be paid till
25 yrs current Top its retirement
provisions
Other than the 7 cost-plus based wind IPPs, all power generation facilities in this
category assume the variability of wind risk. This means that the Federal Government
is not obliged to make any capacity payments to these IPPs regardless of their
utilization.
Even in the case of the 7 cost-plus wind IPPs, where the Federal Government has tied
itself with mandatory capacity payments based on determined benchmark levels,
the quantum of capacity payments is not significant enough to affect the overall
annual capacity payment of the sector. The projects in this category are therefore
largely aligned to the proposed TaP contractual arrangement.
Therefore, the Federal Government should shift their contracts from ToP to TaP
immediately after the payment of their respective long-term debts.
If negotiations with the relevant IPPs are unsuccessful, some of the power plants are
recommended to be retired. For this purpose, a study of the Tentative Dispatch Plan
2020 (prepared with help of SDDP Software) was undertaken, which has also
analyzed the past six-months and expected future utilizations of the plants
established under the said power policies. Plants with less than 3% future expected
utilization (as per NTDC's estimate) have thereby been identified for the purpose of
shut down. Details are contained in Annexure 1K.
85
Based on this methodology, a total of 9 power plants under the 1994 Policy and 5
power plants under the 2002 Policy have been shortlisted. However, before arriving
at a final informed decision regarding retirement, a technical feasibility in this regard
may be carried out to address constraints which may arise due to closure of these
plants such as overloading of the system, low voltage issues, stability issues, etc.
A review of the standardized PPAs and As for the 1994 and 2002 power policies
signed with IPPs was also undertaken and an overview of compensation clauses as
well as legal clauses covering termination is given at Annexure 1 L, while the policy-
wise outcome is given below.
The compensation amount required to be paid for retiring the plants under the 1994
Policy could not be worked out as component (c) of the compensation amount
listed in the Implementation Agreement ("IA") is based on Net Cash Flows of the
project which were presented to the lenders at the time of Financial Closing in the
90s which was not available with the Committee. If the Federal Government decides
to go ahead with the closure of these plants, this information will have to be obtained
from the lenders or the IPPs.
In order to determine the compensation amount required to be paid in line with the
IA for retiring the plants under the 2002 Policy ("Termination Cost"), the relevant
information for IA's compensation components (a), (b), (c) and (d) was obtained
from NEPRA's tariff determinations and audited financial statements of the respective
IPPs.
Capacity payments which will be required to be paid to these IPPs for the remaining
lives of the projects, regardless of their utilization in case these are not retired, was
also calculated assuming the same growth in tariff components as observed in the
past. These excess capacity payments will be more than what the potential
termination cost would be and therefore, the difference between the two would
actually be savings for the Federal Government of Rs. 188.74 billion for four plants
under the 2002 Policy:
86
Table 46 - Difference between Termination Cost and Excess Capacity Payments
314. It is pertinent to note that these workings and future projections have been prepared
as per the latest reported financial statements/financial data i.e. June 30,2019 which
are applicable if these projects are retired before June 30, 2020. If retired after June
30, 2020, the calculations will change. This working will also require further verification
by an independent auditor before a final decision is taken. An IPP-wise detailed
analysis for retirement of these 4 IPPs is provided in Annexure 1M.
If the plants set up under the 1994 and 2002 Policies agree to shift to Tap, then it is
irrelevant whether these plants remain in operation or retire because the Federal
Government will not be liable to pay them any capacity payments and will only pay
them in accordance with actual power generation.
87
Strategy for Way Forward
317. The Federal Government has two options for addressing the problems identified in
tariff and operations of IPPs:
OPTION 1
318. A negotiated settlement is the preferred option which will require engagement of all
stakeholders with a view to arrive at an agreement which ensures that Pakistan's
power sector is financially and operationally sustainable in future. This will also be in
the interest of the IPPs since they will be able to receive timely payments.
OPTION 2
319. The Federal Government can undertake a forensic audit of all companies with a view
to establishing further wrongdoings which were not identifiable under the scope of
this Report. This will require a 2-pronged approach discussed below.
320. Various risks were discussed during the review of IPPs which could not be addressed
on account of limitations pertaining to budget and the need for a detailed forensic
audit. Suspicion was raised about the authenticity of the projects' set-up cost figures
submitted by IPPs which may have allowed some investors to recover their equity at
the start of the projects, and therefore, any return being paid to them by the Federal
Government is unjustified. Similar observations were made about quantity and quality
of fuel/coal used by certain IPPs while submitting inflated invoices to CPPA-G.
322. Accordingly, the companies which are found to have misrepresented or misreported
may be proceeded against as per applicable law, including potentially in
88
accordance with Section 16.1(f) of the standard PPA which identifies "any
statement,
representation or warranty by the Company
in this Agreement (or in a certificate
delivered pursuant to Section 2.8) proving to have been incorrect, in any material
respect
when made or when reaffirmed and such incorrect statement,
representation or warranty having a material
adverse effect on the Company's
ability to perform its obligations under this Agreement or having
a material adverse
effect on the rights or obligations of the Power Purchaser under this Agreement;"
as
an event of default by the company.
323. The setup cost of two coal-based plants, HSR and PQEPCL, reported in the financial
statements seems to be considerably high. A preliminary analysis revealed that a
power plant with similar technology is planned by the Jamshoro Power Company
Limited (a Federal Government owned company) for which International
Competitive Bidding was carried out for EPC contract as required under PPRA rules.
As a result, the EPC price of around USD 875 million was established for the two units
of 660 MW, which works out to USD 0.66 miffion/MW.
324. However, the actual capital cost without jetty allowed to HSR under the lipfront Coal
Tariff 2014 at the CoD stage was 1.00 million/MW (USD 1,321.75 million). Although the
capital cost of HSR cannot be directly compared with the EPC cost of Jamshoro since
capital cost includes EPC as well as non-EPC components, the difference of around
USD 450 million between the capital cost and the EPC cost cannot justify the capital
cost approved for HSR. This establishes the possibility that various power sector
investors are taking out their equity upfront by over-invoicing the cost of EPC or plant
and machinery.
325. During the review of the tariff documentation, it was noted that the revision in of the
1st Upfront Coal Tariff in 2013 was made because of a reconsideration request filed
by the Federal Government through the then Ministry of Water and Power
("MoWP")
wherein it was stated that
"the investors based on their market due diligence gave
feedback to the MoWP/Federal Government that IPP projects opting for the
above
determined Upfront Tariffs would not be commercially viable. Interactions with
different investors have shown that following items need to be rationalized for viable
investment in coal-based Power Generation Projects.
89
Reconsideration of Per Megawatt Capital Cost of the Project
The outcome of the feedback given by private sector investors suggests that capital
costs as assumed by NEPRA for 660M W unit are on the lower side. While comparable
gross capital cost for plants manufactured in Europe and America would range
between US$ 2-3 million per megawatt, even that based on the Chinese
manufactured power plants would not cost lower than USD 1.45-1.70 million per
megawatt."
With this background, where the information originated from the investors for revision
in tariff and other benchmarks, and not based on proper due diligence by NEPRA,
the possibility of overpricing in the setup cost is further substantiated.
ACTIONS BY NEPRA
NEPRA, in its statutory mandate under the NEPRA Act has the power to address issues
in tariff determinations including systemic issues 38 by reviewing its earlier
determinations in terms of section 7(1)(g). Further, section 7(6) of the NEPRA Act binds
NEPRA to protect the interests of consumers and companies providing electric power
services in accordance with the principles of transparency and impartiality.
In addition to determining rates, charges and other terms and conditions of the
supply of electricity services, NEPRA can also review its orders, decisions, or
determinations39. Proceedings in this regard can be initiated by NEPRA either on its
own motion or on an application of an interested party.
NEPRA may initiate proceedings for recovery and rectification in respect of following
matters:
38 Like oversight in IRR calculation, debt repayment mismatch and duplication of currency depreciation in return.
39 Section 31(2) and (3) of the Act.
90
Excess profits made by IPPs on account of fuel and O&M costs, etc. under the
2002 Policy;
Excess recovery of fixed costs from IPPs set up under the 2006 Policy including
the bagasse Framework 2013.
330. Excess set-up cost allowed to the 2015 Policy IPPs may be addressed by NEPRA in the
pending CoD tariff review petitions of coal based IPPs or through a re
-determination
of tariff.
In order to avoid any uncertainty with regard to the payment of excess profits in
future, NEPRA may also add a provision in its tariff determination for claw back or
sharing of such excess profits on a reasonable predetermined basis as discussed
above.
Further, CPPA-G, under the supervision of NEPRA, needs to ensure compliance of PPA
provisions including the requirement of minimum fuel inventory for which cost of
working capital has been allowed to the IPPs and any non-compliance should be
adjusted against the tariffs.
NEPRA can also undertake various enforcement actions against the generation
companies in accordance with Chapter 111A of the NEPRA Act. Under section 278
of this Act, a penalty can be imposed on a company of a minimum of ten million
rupees which may extend to two hundred million rupees and, in the case of a
continuing default, with an additional fine which may extend to one hundred
thousand rupees for every day during which the contravention continues. Further,
under section 27C, NEPRA can:
i.
Prohibit a generation company, a licensee or a registered person, from
providing electric power services; or
U.
In the case of a generation company, prohibit any or all persons from
purchasing electricity from such generation facility; or
91
iii. Require a generation company, a licensee or a registered person, to improve
the provision of electric power services so as to ensure compliance with this
Act and the rules and regulations made thereunder.
NEPRA may also suspend or revoke the generation license under section 28 of the
NEPRA Act, in case the concerned company fails to comply with an instruction issued
by NEPRA.
Since tariffs are determined on the basis of information provided by IPPs, there are
many instances where the systemic tariff issues are caused by factually incorrect
information provided to NEPRA at the time of seeking the tariff. For example, heat
rate curve and O&M estimates in case of 2002 Policy as well as detail of financing
costs in case of the 2015 Policy were provided by IPPs whereas annual plant capacity
factor data in case of the 2013 Framework was provided by PSMA.
Under Pakistani law misrepresentation of material existing facts made by one person
to another with knowledge of its falsity and for the purpose of inducing the other
person to act, and upon which the other person relies with resulting injury or damage
is defined as fraud. It may also be noted that tariff determination is deemed to be a
decree of a civil court under Section 40 of the NEPRA Act, which provides that:
It is worth mentioning that the Federal Government has from time to time made
amendments in the policies post its approvals. For instance, in the Power Policy 2002,
sixteen amendments on different subjects were approved as reported on the PPIB's
92
website. The majority were incorporated to cover the risk of investors and the most
important ones related to USD indexation of returns and allowance of return during
construction. These were made with retrospective effect.
ii
339. There is therefore precedent supporting such a move by the Federal Government,
and this time, it will be in the interest of consumers and overall economic health of
the country which will be protected.
93
SECTION 2 - CIRCULAR DEBT & DISTRIBUTION INEFFICIENCIES
For the purposes of this report, the circular debt stock includes:
H. The amount picked up from CPPA-G by the PHPL by funding it through Federal
Government guaranteed borrowing.
Additionally, the circular debt flow is the marginal change in outstanding stock of
circular debt.
The problem was triggered by a sharp rise in the cost of generation fuelled by:
94
Oil's share in electricity generation vs. Brent
Overdue Trade Debts of Three IPPs
45%
110 140
40% 120
95
35% c 100
BO
30% BO
65
25% LI, 60
SO
20% 40
35 20
15%
20 in
I I
In 1/40 t-•
cm a, 0 0
>• to
La, t.r., I x. ?z: ?z:
ma Oil's share In electricity generation
Brent (RHS) Overdue Trade Debts of Selected IPPs
Data Source: Energy Yearbook
Pakistan's reliance on oil for electricity generation rose sharply in the 1990s when
RFO-based power plants were setup by IPPs. However, the early 2000s witnessed a
surge in Pakistan's natural gas production and the share of oil in electricity
generation fell to less than 16% by FY2005 from almost 40% in FY2000.
By mid 2000s, oil prices surged globally, causing a dramatic shift in domestic gas
consumption pattern, which was priced very low relative to oil, therefore its
demand from other sectors including transport (CNG) and industry (captive power)
increased substantially. Concurrently, the domestic production of natural gas
levelled off and subsequently started to decline.
This caused a curtailment of natural gas supplies for grid electricity generation
thereby increasing the reliance on RFO again. The share of oil in electricity
generation jumped to 35% in FY2009 from 16% in FY2005 as illustrated in the chart
above. Moreover, hefty PKR depreciation following the 2008 crisis magnified the
impact of increasing share of oil in electricity generation pushing the cost of power
generation higher. Between FY2005 and FY2010, the cost of generation increased
by 148% while average consumer tariff went up by only 33% during this period as
tabulated below:
95
Table 48 - NTDC System - Cost of Generation vs. Average Selling Price
(PKR/KWN
348. Success ve governments have relied on heavy budgetary suppor and quasi-fiscal
financing to eliminate the circular debt, but these measures addressed the
symptoms and not the root cause, therefore the problem has only deepened.
500
Budgetary Support to Power Sector Outstanding Stock of Circular Debt
450
400 1800
350 1500
• 300 =1200
0
65 250
co 900
200
0- 600
150
100
0 300 I I I
5 I II I
0
Lrf_i r_, crsi
2 2 2
E CPPA • PHPL
Subsidies • Other Liquidity injection
The cumulative budgetary support to the power sector amounted to PKR 3,202
billion from FY2007 to FY2019 comprising:
Yet, the circular debt stock has continued to grow and increased by PKR 465 billion
in FY2019 to a total of PKR 1.6 trillion. With public indebtedness (public debt/GDP)
having increased to 85% in FY2019 from 52% in FY2007, the Federal Government's
ability to provide fiscal support to the sector is severely constrained.
40
This was a part of PKR 480 billion circular debt settlement made in Jun-2013. PKR 342 billion injection was shown as net
lending (Others) in the fiscal accounts.
96
CIRCULAR DEBT FLOW
351. At the micro level, the flow of circular debt is attributable to:
I. A high cost of generation;
U.
Transmission and distribution Inefficiencies; and
Ili. Regulatory and fiscal inefficiencies.
Mt"
1,344.4
2.1 2.2 -•--
EPP 3.3
5.2
7,5 7.9 _•
PPP 4.9 5.7
PKR/K9A 9.6 10.1 72
PKR/LISD (Avg.) 82 94 10.9
96.8 103.0
EPP
=NM 2.2
72
2.2 2.5
1043 104.8
3.2
110.0
3.5
136.4
32
7.7 6.4
_PPP 4.6 5.0
MOM 9.9 9.9
4.2
8.9 6.9 7,8
The total CPP increased from PKR 212 billion (PKR2.2/KWh) to PKR 640 billion (PKR
5.2/KWh);
The total EPP decreased from PKR 754 billion (PKR 7.9/KWh) to PKR 705 billion (PKR
5.7/KWh); and
The total PPP (CPP + EPP) increased from PKR 965 billion (PKR 10.1/KWh) to PKR
1,344 billion (PKR 10.9 /KWh).
dl
The comparison with FY2014 is illustrative as it was the year of high oil prices with Brent averaging -USD 110.
97
354. A host of factors have contributing to this high cost of electricity generation:
356. Since FY2015, about 12,100 MW of net power generation capacities have been
added to the power system while another 12,400 MW would be added by FY2025.42
357. The new power generation capacities have indeed helped lower the overall fuel
cost per unit as they are based on cheaper fuels than furnace oil. However,
comparing FY2016 with FY2019, the increase in CPP outweighs this reduction in EPP
on per unit basis in both PKR and USD terms. The total CPP amount increased from
PKR 275 billion (PKR 2.7/KWh) in FY2016 to PKR 640 billion (PKR5.2/KWh) in FY2019.
98
358. Further, the front-loaded structure of ToP generation tariffs plus surplus capacity are
contributing to a higher CPP component in PPP on per unit basis. While the PPA
terms of power producers range from 25 to 40 years, depending on the technology
in question, their tariffs are based on debt repayments of 10-12 years. This cliff-edge
structure of power producers' tariff becomes a bigger problem when large
I
capacity additions are crammed within a relatively short span of time, which is the
situation presently confronting Pakistan.
250 150
0
-9- 200 120
150 a 90
Lea
100 9I,6 77:
91.6 60
50
30
0
Year 1-10
Year 11-30 Year 1-12
Year 13-40
O&M/Others • ROE • Debt
eu O&M/Others P ROE • Debt
Data Source: NEPRA
Data Source: NEPRA
359. As covered in Section 1, generous USD based ROEs, high cost of debt servicing,
weak regulatory oversight and ToP contracts have led to enormous payments to
IPPs and have added to the burdensome capacity payments. This has not only
increased the cost of electricity generation but has also contributed to deepening
the culture of rent seeking thereby causing much larger costs to the economy by
undermining risk taking and driving resources away from other sectors.
360. Moreover, high interest spreads allowed on project debts of IPPs have enabled
lenders to benefit at the expense of electricity consumers. Likewise, LPS rates are set
at KIBOR + spread (up to 4.5%), while the IPPs' borrowing costs actually are much
lower.
99
361. The box below provides a perspective on the excess setup cost of a transmission
project and saving in case the tariff structure is revised to a TaP regime. This project
is significant for understanding future capacity payment liabilities.
With the induction of medium and long-term plans of power into the national grid, the Federal Government framed the Transmission Policy
2015 for private sector participation in transmission lines infrastructure. For transmission of surplus energy to the northern region, NTDC and State
Grid Cooperation of China (SGCC) signed a cooperation agreement on April 20,2015 for development of ±660 kV 4000 tv1W Mafiari to Lahore
High Voltage Direct Current (HVDC) Transmission Line. This Project is included in the priority Projects under China Pakistan Economic Corridor
(CPEC). Under the said cooperation agreement, both parries nominated subsidiary of SGCC i.e. China Electric Power Equipment and
Technical Company Limited "CET to develop the facility on BOOT basis and will also be the EPC contractor. Accordingly, PPIB approached
NEPRA for award of tariff to the project requesting USD 2,119.68 million project cost. NEPRA after the end of the proceeding approved a total
project cost of USD 1658.34 million in November 24, 2016.
Within the approved cost of USD 1658.34 million, USD 1,000 million was approved for converter stations. Since the project was awarded unde
CPEC, through government to government agreement, hence, no bidding was carried out for award of this project. Because of lack of
competition in this important infrastructure project, the first of its kind in Pakistan, it was natural to see whether the cost approved is reasonable
and not excessive.
Due to budgetary constraints, a detailed global comparison with similar technology projects could not be carried out. However, it was noted
that a similar project was awarded in January 2017 in India through international competitive bidding at the time when Lahore-Matiari HVDC
project approvals were given. The winning bidder, ABB, a Swiss-Swedish multinational corporation headquartered in Zurich. Switzerland press
release indicated that it was selected by Power Grid Corporation of India Ltd. to deriver the ±800 kV, 6,000 MW Raigarh - Pugalur Ultra-HVDC
link, which will transmit power from central India to consumers in the south, a distance of 1,830 km (the longest in the World)'. In the agreement
the convertor station cost was USD 640 million. If convertor station comparison is made on MW basis, the approved cost for the Chinese
Company works out to be 2.34 times more than the ABB's bid as illustrated below:
1h 1 cflTiflt
Description •
11 is worth highlighting that the Indian transmission fine project is high in specification as well as length and is still cheaper by USD360 million. The
impact of high cost of con ract will be the contributing factors for high cost of energy for consumers in future due to capacity payments. The—
project is currently under construction therefore, it is proposed to conduct forensic audit of the project by the Federal Government, and i
case of any adverse findings, get the project cost reduced too prudent level. For future, international competitive bidding should be the most
preferred route of discovery of contract prices.
Further, the HVDC project is awarded tariff under the take or pay regime. There are possibilities where the HVDC fine may not be utilised as per
the 98.5% approved availability because of a) outages of power plants in addition to scheduled and allowed forced outages, b) reduction
in demand during off summer seasons, and c) increase in demand/consumption of Southern region, etc. As a result, the consumers will pay
the capacity charges. To avoid the payment of underufilization through the Fixed capacity payments, it is recommended to shift the structure
of project from the Current Take or Pay to Take and Pay. Depending on the utilization factor the saving over the 25 years concession period
will range from PKR. 135 billion I& 90% utilization factor to PKR. 677 billion OD 50% utilization factor as detailed below:
100
1'4!
"In 1986,aaformula
propose committee headed by of
for calculation Mr. A.G.N. Kazi, the then Deputy Chairman Planning Commission, was established to
NHP.
IS
Besides having NHP, hydel levies also include a small portion of IRSA charges @ PKR 0.005 per kWh payable on entire
WAPDA fleets' generation and PKR 0.15 per kWh water use charge payable only on Mangla hydel plant. Both of these
charges (IRSA/WUC)
because of NEW. remained in the range of PKR 800-1100 million demonstrating that the jump in levies are only
r-
101
Table 50 - WAPDA: Generation, Sales Revenue and HP (Rs. Million)
- -Ty li t i VI. D'i t ,TitiO 97 i IV I 0
L I 1:511_ 41
WAPDA Generation (GWh) 29,326 31,204 31,525 33,151 30,797 27,121 30,937
WAPDA Sales Revenue 34,231 36,905 63,185 52,438 62,060 60,629 56,920
Total Cost of WAPDA Generation 41,063 43,920 70,295 64,416 121,325 121,158 160,710
Generation Cost (PKR/KWh) 1.40 1,41 2.23 1.94 3.94 4.47 5.19
TRANSMISSION CONSTRAINTS
NTDC is required to follow a regularly updated merit order for electricity dispatch
listing thermal generating units in ascending order based on their variable costs.
However, as highlighted by CPPA-G: "...transmission network congestions result in
dispatch of expensive generators while cheap generation remains idle owing to
said constraints, thus increasing the overall energy Purchase Price for the system".46
Additionally, because of distribution constraints 47 and guaranteed dispatched
agreed in the PPAs (e.g. RLNG), out of merit dispatch is also undertaken.
CPPA-G's projections of fuel mix for F12020 suggest that generation on furnace oil
would be about 5.2 billion units higher with T&D constraints than without it. Higher
cost of oil-based generation increases the aggregate fuel bill of CPPA-G which is
then passed on to consumers as monthly fuel charges adjustment.
102
367. At present, NTDC's de-rated power generation capacity is 32,767MW, whereas, the
transformation capacity for 500kV and 220kV is 22,950MVA and 30,746 MVA
respectively. Beside the mismatch in transmission network and power generation,
NTDC requires investment in installation of grid stations and transmission if it is
expected to overcome the following constraints:
i. Network constraints at some locations;
369. With a significantly large share of cheaper and must run /guaranteed despatch EPP
plants running on hydro, nuclear, renewable and coal, the probability of the RLNG
based plants meeting the 66% plant factor on merit order is relatively low.
371. There are large variations in the price of natural gas based on its origin (domestic
vs. imported LNG) and usage (residential, commercial, industry, export sector, etc.).
The electricity generation sector is the biggest consumer of RLNG. In general, the
103
consumer price of domestic natural gas is much lower than that of RLNG48 as the
latter's pricing is set on ring-fenced basis.
372. The disparities in natural gas prices have multiple adverse effects:
iii. Supply of domestic natural gas to some of inefficient GENCO units puts them
higher on the merit order than they would otherwise be if gas pricing was
uniform.
Natural Gas Prices for Grid & Captive Power Electricity Generation on Gas - NTDC System
12 45%
10 40%
E2 8 35%
6
30%
2 25%
0 20%
Export Export RLNG RLNG cr2 to) •43
Pakistan imports 800 MMCFD of LNG under Brent linked term contracts. DES price for 600 MMCFD is 13.37% of Brent
48
while that for 200 MMCFD is 11.63%.
104
FINANCING COST OF CIRCULAR DEBT STOCK
373. The financing cost of the outstanding circular debt stock feeds back into even
higher stock of circular debt. If an average current mark-up rate of about 15%, is
assumed, the annual financing the current circular debt stock of PKR 1800 billion
works out to PKR 270 billion.49
Distribution Inefficiencies
DISCOs are government owned entities, administratively working under the Pakistan
Electric Power Company ("PEPCO") which is headed mostly by a Government
official on a part-time basis.
Ti
The DISCOs collectively have a country-wide customer base of 28.473 million
consumers in domestic, commercial, industrial, agriculture and bulk categories, with
domestic being the most dominant with 85.92% share in terms of number and
48.56% in terms of consumption. Within the domestic class, 78.13% consume
1 electricity up to 300 units per month.
The second largest consumer category is industrial consumers with 25.87% share of
the total sales mix. The consumption wise sales mix of different category of
consumers is given below:
The actual mark-up charged for FY2019 amounts to PKR 95 billion as per CPPA-G's billing which does not include mark
up to public sector generators. Further, the interest payments to IPt's are negotiated leading to lower LPS. About Rs. 800
billion is parked at PHPL with a mark-up of KIBOR + 80bp. Assuming KIBOR of 13.63% at June 2019 w/ 0.8% spread, the
carrying cost of PHPL is Rs. 116 billion. These numbers are based on circular debt of Rs. 1,600 billion as on June 30, 2019. As
circular
year will debt has increased
be around to Rs. 1,800 billion and LPS negotiations vary every year, carrying cost of circular debt next
Rs. 270 billion.
105
While there are large variations in operational performance amongst the DISCOs,
the distribution sector as a whole forms the weakest link in the country's electricity
supply chain. The main reasons of operational inefficiencies of DISCOs are:
i. T&D losses;
T&D LOSSES
For every 100 units of generation in the Power System during FY2019, about 3 units
were lost during transmission and a further 17 units were lost due to T&D inefficiencies
at the DISCO level, i.e. about 80 units were sold. The cost of 15 units lost due to
system inefficiencies is allowed by NEPRA which means that the cost of only 2 units
is borne by the DISCOs. At the billing level, the system is further burdened with 9%
under recoveries. This translates to a loss of Rs. 32 billion due to T&D's inefficiencies
and an additional loss of Rs.120 billion50 due to under recovery.
As shown in the charts below, the disaggregated data reveals large variations in
T&D losses across DISCOs with lowest of 8.9% for IESCO and highest of 37% for PESCO
and SEPCO. Clearly, size (in terms of coverage area and/or units purchased) is not
a determinant of T&D losses. SEPCO is only 1/5th the size (units purchased) of LESCO
while its T&D losses are 2.8 times as high as LESCO's.
SEPCO, 19.0%
45%
PESCO,
40% 37.1% 18.5%
35%
HESCO,
30% 29.5% 18.0%
25% MEPCO.
QESCO, 15.8%
20% 216% 17.5%
15% lip GEPCO.
9.9%alkink 17.0%
10% TESCO, mew 41 13.52C,,A
PESCO, 411LE Q, 42) N CO
er 1-1
0 0 0 0 0
5% 12.0% 1ESCO, 9.8%
0% 8.9% E' El
00 10.0 TWII 20.0 30.0 DISCOS's T&D Losses
Wm Souks, PUCE) Esisrsy Yearbooks NEPRA
Data Su
50 The impacts have been calculated using weighted average rates applicable during FY 2019.
106
380. The evidence from KE suggests that with governance improvements and
investment, there is scope for significant reduction in DISCOs' T&D losses. KE's T&D
losses halved from over 40% in FY2000 to -20% in FY2019 as show in the chart below.
Over the same period, DISCOs aggregate T&D losses have shown a more modest
reduction of 230bp, from 20% in FY2000 to 17.7% in FY2019.
107
illegal connections. Further, the administration is inefficient regarding timely
replacement of defective meters and monitoring/surveillance of network;
BILLING UNDER-COLLECTION
Another issue for DISCOs is under-collection of amounts billed to customers. Their
overall collection/billing ratio averaged around 91% over the past 7 years (FY2013-
FY2019). The cumulative shortfall in collections over billing during this period
amounted to PKR 633 billion of which FY2019 alone accounted for PKR 132 billion.
The shortfall in collections from customers impairs the ability of DISCOs to meet their
obligations towards CPPA-G which further deepens their cash flow deficits by
payment of taxes on uncollected bills. KE also falls behind in payments to CPPA-G
for electricity purchased from the NTDC System. CPPA-G's receipts from KE in FY2019
were PKR 42.4 billion lower than the amount billed during the year.
140 95% SO
93% 40
120
c 30
-9100 91%
.,,-. c 20
co o
cc
x 80 89% l:=1
a. OS 10
g
54
60 87% a, 0
II
FY14 FY15 FY16 FY17
1 II I 85% -10
40
m .:_t4 Ln 2 n, co cc,
51 5-1-. >1 -20
384. As with the T&D losses, the collection/billing ratio varies substantially across DISCOs.
Over the last 7 years (FY2013-19), the average collection ratio for individual DISCOs
ranged from nearly 100% at the higher end to less than 40% at the bottom of the
108
table. Unsurprisingly, the DISCOs with lower T&D losses generally have higher
collection rates and vice versa.
100%
40 100%
90%
35
80% 80%
30 i
70%
25 1 60%
60%
20 ?
40%
50%
I.
15
40% 20%
10
30%
0 59
LI c_t 4)
0
Li
0 00000 0%
LI 0. LI tJULJUUU 0 0 0 0
LI LI En too so Le O. VI 4J Li 0 0 0 0 0 0
-1 LI 1st tal III Le se 4.1 LE 4.1 c..) Li L.)
E- tn D, v: LI fl , LI vs v: fl, tal
LI
Le 0
-) se le
Cl, LI ve Se 14 Se se
a. I En Cy
S Collection/Billing T&D Losses (RI-IS) Domestic 01 COM M. PE Industrial •Agri •
Others
Data Source: PEPCO Data Source: PEPCO
385. DISCOs' receivables from private sector defaulters amounted to PKR 628 billion at
end of Dec-2019, comprising PKR 525 billion due from running defaulters and PKR
103 billion recoverable from disconnected (permanent) defaulters. More than 87%
of the amount recoverable from running defaulters and around 84% of that from
disconnected defaulters is overdue for more than 3 years. Also worrying is the
unbridled growth in the amounts due from running defaulters who continue to
receive electricity despite non-payment. The increase in these amounts creates
doubts if they represent disguised T&D losses (excess billing) or genuine billing.
109
386. Of the total Rs. 525 billion due from running defaulters at Dec-2019, QESCO
accounted for nearly 48.7%, followed by SEPCO (17.6%), PESCO (11.4%), HESCO
(11.1%) and TESCO (8.7%). As for the Rs. 103 billion recoverable from disconnected
defaulters at Dec-2019, PESCO had the lion's share at 45.3%, followed by HESCO
(14.4%), SEPCO (13.7%) and LESCO (13.1%).
Table 54-- DISCO Wise Amounts Due from Running and Disconnected Defaulters
--:
Rants.Defaults, '.-1r--:77-;- •--c it}1,
INFRASTRUCTURE CONSTRAINTS
Power delivery through DISCOs' networks mainly depends on the adequacy of
transformation system (132/11 kV transformers), 11kV feeders (circuits) and finally the
distribution transformers and low voltage circuits. Overloading of secondary
transmission and transformation system, distribution lines and transformers are
serious threats to the sustainability and quality of power supply.
Loading capacity of power transformers should ideally be kept at 80% for optimal
utilization, beyond which it is categorized as overloaded power transformer. It was
observed that out of 2025 transformers among all DISCOs, 23.01 %were overloaded
in FY 2017-18. Worst performers were PESCO, HESCO and SEPCO with 52.97%, 40.50%
and 38.89% respectively having overloaded transformers. IESCO and LESCO had
only 0.81% and 3.59% of their transformers overloaded.
110
LOADING POSITION OF 11 KY FEEDERS (CIRCUITS)
389. Overloading in feeders increases the losses as well as frequent interruptions in power
supply besides low voltages at consumer end. Overloading (above 80% utilization)
on IlkV feeders stood at 23.49% in FY 2017-18 across country-wide 8850 feeders.
TESCO's position was the worst with astounding 100% of its 11 kv feeders overloaded
followed by PESCO at 40.71%, SEPCO at 32.04% and QESCO at 32.56%.
393. While all DISCOs are adversely impacted by the fiscal ambiguities and tax drag.
IESCO and QESCO are the biggest victims. At end Dec-2019, IESCO had Rs. 88.5
billion in outstanding receivables from the government of AJK while QESCO had Rs.
19.4 billion receivable from the provincial government and another Rs. 37.2 billion
in tariff subsidies due from the Federal Government. IESCO's receivables from the
government of AJK reflect the differential amount based on notified tariff and the
tariff at which the government of AJK has been making the payments. As for
QESCO, unpaid subsidies on agriculture tube-wells is the main issue.
394. KE's trade receivables from government and autonomous bodies amounted to Rs.
43.5 51 billion at end of FY2018, which is the latest year for which its financial
statements are available. In addition, the company had Rs. 49.3 billion in tariff
subsidies due from the Federal Government. KE's payables towards CPPA-G, SSGC
and PSO amounted to Rs. 87.5 billion (which rose to Rs.135 billion for FY2019), Rs.18.8
billion and Rs.2.4 billion at end F12018.
395. The taxation regime is also a significant drag on DISCOs' cash flows. The companies
carry large refund/input adjustment claims of sales tax and other government levies
on their balance sheets. The problem is even bigger for DISCOs that have lower bills
collection but have to pay taxes even on uncollected/defaulted electricity bills. For
example, QESCO had gross amount of Rs. 37.7 billion as duties/charges and tax
receivables on its balance sheet at end FY2018 against which it had made provision
for doubtful receivables amounting to Rs. 17.8 billion.
5 This the principal amount only. An additional Rs. 6.5 billion showed as LPS receivable from these entities.
112
WAY FORWARD - CIRCULAR DEBT & DISTRIBUTION
INEFFICIENCIES
This section lays out specific measures to address the fundamental causes of the
circular debt problem along with suggested reforms for the distribution segment of
the power sector.
Altogether, they can become part of a circular debt resolution plan that meets two
essential criteria of sustainability:
Given the binding constraints of a weak fiscal position, already high consumer-end
electricity prices and rising cost of generation, out-of-the-box solutions are required
to eradicate the existing circular debt stock or at least minimize its ongoing financial
drag. The following are proposed measures for dealing with the existing circular
debt stock.
52
The amounts on PHPL's books carries mark-up rate of KIBOR + 80bp while the rate of IPS on overdue payables on
CPPA-G-G's books is up to KIBOR + 4%.
113
Table 57- DISCOs' Receivables at end Dec-2019 (Rs. Million)
402. The total savings relating to the past periods would yield reduction in the
outstanding stock of circular debt.
114
federal and provincial governments- after the 18th Amendment. Most importantly,
such areas include public debt and the electricity sector, which pose considerable
claims on public finances.'
404. In the section on considerations for the next NEC Award, the IMF report suggested
that 'provinces participation in reforming the power distribution sector as well as
sharing the burden of liabilities arising from delays with such reforms should be
considered.' A mechanism may therefore be devised for sharing the burden of
electricity subsidies and the outstanding amount of circular debt between the
centre and the provinces.
407. The net stock of the circular debt may need to be absorbed into the public debt.
However, history suggests that such stock settlement of outstanding amounts
induces a sense of complacency at both political and institutional levels, which
eventually result in relapse of the problem with even bigger magnitude. It is
therefore critical that any settlement of principal amounts becomes part of a
comprehensive plan which ensures that circular debt flow is also stopped while
stock is eliminated.
408. A one-time increase in public debt to remove the stock can be linked with
quantifiable KPIs and an accountability mechanism whereby future savings due to
115
reduced cost of generation and other measures outlined above are used to pay
back this increase.
409. To minimise the fiscal cost of removing the outstanding stock from CPPA-G/PHPL
books, different structures may be evaluated. These could include, among other
options:
410. The SBP extends re-financing to banks for exports and other priority sectors at 2% for
short-term and 3% for long-term loans. The total amount of financing to banks under
various schemes amounted to PKR 578 billion at end Jun-2019. The
repayment/servicing of the amount of circular debt transferred to the SBP's books
could be from retention of 20% profits by SBP before any transfers to the federal
government.
Units generated;
Units billed; and
Units for which bill collection takes place.
116
Table 58 - Estimated Cost of Electricity FY2020
PKR/USD 155.0
Generation
126.5
Billing
102.1
Collection
92.3
(USt/KWh) (1154/KWh)
Cost of Electricity (1.15C/KWh)
10.6 13.1
Cost of Electricity (after subsidy) 14.5
9.6 11.9 13.2
Use of System charge and Distribution Margin are based on actual FY2019
values adjusted for inflation.
413. As evident from the above table, an average consumer tariff (excluding taxes) of
PKR 20.5/KWh (USO 13.2/KWh) for FY2020 would be required for recovery of all direct
1
and indirect costs of electricity supply, assuming that demand remains inelastic to
117
further increase in tariffs. This is 26.5% higher than the DISCOs' average sale rate of
PKR 16.3/KWh54 (USO 10.5/KWh) for Dec-2019.
NTDC System - Gen Cost vs. Selling Price (PKR) ) NTDC System - Gen Cost vs. Selling Price (USD)
20 12
11
15 I
, 9
10
10 g
44 8
7
6
5
0 4
d• Lal $.0 N CO 0,0 ri NI CO el' N 0 CA CI)
)). L'a .9, ;1 .`?-1 '41 ?-;
U. U. U. to. rz LEFEEEEEEEEEEEEEEliea
aI
Cost of Generation —Avg. Selling Price (ex-taxes) Cost of Generation Avg. Selling Price (ex-taxes)
The electricity tariffs are already at record highs in both PKR and USD terms as
evident from the above charts and further increases would be unsustainable. It is
therefore imperative to reduce the cost of electricity generation. The following
paragraphs explain a number of remedial measures that can help bring down the
cost of electricity and stem the flow of circular debt.
CAPACITY PAYMENTS
RE-PROFILING CAPACITY PAYMENTS
This aspect was touched upon briefly in the Way Forward part of Section 1, however,
it is covered here with the objective of highlighting measures beyond the review of
IPP contracts.
Debt servicing accounts for nearly 50% of the total CPP in FY2019, followed by ROE
with a share of 30% while fixed O&M/other costs account for only 20%. Out of the
total CPP of PKR 640 billion in FY2019, the share of public sector generators (WAPDA,
GENC0s, NPPs and government owned IPPs) comprised PKR 318 billion or almost
50%. In addition to the under-construction power projects in the private sector, a
number of large projects are at advanced stages of completion and will be
118
commissioned between 2020 and 2023 including 2 x 1100 MW NPPs (KANUPP 2 & 3),
1200 MW 4th RLNG based IPP and 2 x 660 MW coal fired plant of Jamshoro Power
(GENCO-I). Therefore, the share of public sector in total CPP shall continue to range
between 45-50% over the next 5 years.
417. While the total annual capacity payment bill has already snowballed from PKR 275
billion in FY2016 to PKR 640 billion in FY2019, CPPA-G projects it to increase to almost
PKR 1,600 billion in FY2025. In terms of fuel source of plants, the combined share of
hydro, nuclear and coal-fired power plants in aggregate CPP would range
between 60-70%.
C,
to
>-• >.•
e.
Pubic Sector • Private Sector
Data Source: OVA-G. Committee Estimates Hydro •Nucelar lCoai • RFO flIGas 'Renewable
Data Source: CPPA-G, Committee Estimates
418. The following provides a perspective about the contribution of different clusters of
power plants to current and future total CPP:
WAFDA,
Total CPP of the II RFO-only power plants would continue to stay above PKR 60 billion a year.
119
419. Though the Government should immediately start work on coming out of all ToP
arrangements and move towards TaP contracting as suggesting in Section 1, it
needs to act immediately on:
Imposing a moratorium whereby no new power plants come online for the
next few years. The exception would be the conversion of existing wind farms
into hybrid wind-solar model with the aim to improve system stability, address
intermittency and lower overall tariffs;
Reducing the spreads over KIBOR/LIBOR for the long-term project debts;
However, KE can help absorb the surplus capacity of the CPPA-G' contracted
capacity by taking an increased supply of electricity directly from the NTDC
network and/or novation of PPAs of some CPPA-G's contracted new coal based
IPPs located near Karachi.
120
There have been significant additions of power generation capacities in the
southern part of the country including 2640 MW imported coal-based plants, 660
MW Thar coal power plants and several wind farms. Moreover, another 4,120 MW
power plants presently under construction including 2200 MW NPPs, 1320 MW coal-
based projects and 600 MW WPPs, would be commissioned within the next 24
months and more power plants shall be added in the subsequent few years.
As the government pursues its policy of power sector deregulation with shift towards
wholesale competitive markets and separation of distribution and supply
businesses, a more integrated national grid system would be required. A detailed
technical study on integration of NTDC and KE Systems must be carried out in
increasing the supply from NTDC to KE grid.
This would also identify any network constraints prohibiting to meet the required
demand of KE from NTDC system which could warrant capital expenditure to be
financed by NTDC and/or KE depending on the geographical/network jurisdiction.
1
However, the capex for improvement of the existing network, let alone the time to
complete such improvements, is going to be relatively low compared to building of
new power plants to meet the same demand. In the latter, tariff would involve an
attractive fixed return, a high debt cost and a NEPRA approved ToP tariff regime.
Therefore, ideally, KE should halt generation expansion projects until that study is
completed. KE system with under capacity can thus help reduce the impact of
capacity payment in the over supplied national grid by selling excess power to KE
subject to commercially agreed terms.
Natural gas is the predominant fuel for captive power generation although coal,
biomass and solar PV are also gaining traction as fuel sources for self-generation.
Cost and reliability are the two main factors for the industry's preference of captive
power over the grid. Captive power generation is cheaper than grid electricity and
its supply is reliable (i.e., uninterrupted and stable). Moreover, the cost advantage
of captive power is even bigger for industries such as composite and value-added
121
textile units, which use combined heat and power to meet their twin requirements
of steam and electricity.
429. The table below shows a comparison of electricity cost from captive power
generation (on natural gas) versus grid electricity for the export-oriented industry or
that supplying to the domestic market.
There are large regional disparities in natural gas prices for same consumer
categories.
431. While Pakistan's export industry supports the electricity tariff of usg 7.5/KWh as
regionally competitive, captive generation remains cheaper at current natural gas
prices and the cost advantage is much bigger for the industry in Sindh/KPK. For the
industry serving domestic markets, captive generation is slightly cheaper even at
currently high RLNG prices (in Punjab) as the comparable grid electricity tariff is very
high.
432. Further, SNGP accounts for 60% of the natural gas supply to captive power while
the rest 40% is by SSGC. Majority of the captive power plants on SSGC network are
located in and around Karachi and hence fall under the KE's service area.
122
Table 60- Captive power generation in service areas of the two public grid
systems
Electricity Sales from NTDC System to industry
GWh 24,285
Total Electricity Sales from NTDC System
GWh 93,887_
Gas supplied to captive power from SNGP
BEM 75,164
Estimated generation by captive power
7,938
Captive Power/Supply to Industry from NTDC System _
32.7%
Captive Power/Total from NTDC System
8.5%
Sale from RE System to Indusby
GWh 4,248
Total Sale from RE System
GWh 14,276
Gas supplied to captive power from SSGC
51,658
Estimated generation by captive power
GWh 5,456
Captive Power (SSGC)/Supply to Industry from RE System
128.4%
Captive Power (SSGC)/Total from RE System
38.2%
433, The KE System has a net capacity deficit and imports 650 MW from the NTDC System,
while the KE-NTDC transmission link is already operating at maximum capacity.
Realistically, only the industry receiving gas supply from SNGP for captive power
generation can shift to the NTDC system, which has surplus capacity. Assuming all
captive power plants on SNGP network shift to the grid, it would increase total
generation by 6.3% and bring down per unit CPP by 3.3%.
434. The following factors need to be considered while rationalising the energy prices
(gas and electricity) for the industrial sector:
The natural gas price for the export industry may be set at a level such that their
grid tariff becomes at least 5% cheaper than captive generation (at 40% single
cycle thermal efficiency).
The grid tariff for manufacturing industry needs downward adjustment not only
to attract back industry using captive generation but also to pre-empt future
grid defection.
Uniform natural gas prices for same category of industrial customers may be
considered across the country with no regional disparities.
123
ELECTRIFICATION OF ENERGY USE
The global energy sector is undergoing unprecedented transformation due to rapid
advancements in technology, making electricity cheaper and greener. This is
driving the substitution of fuels such as oil and gas with electrification of final energy
consumption e.g. electric vehicles (EVs), space/water heating and cooking - the
needs that were traditionally served by hydrocarbons.
Pakistan's energy55 imports amounted about USD 16.0 billion in FY2019, accounting
for almost 30% of the country's total imports. In this scenario, electricity can meet
our energy needs more efficiently and yield multiple benefits including a higher
base load, lowered cost of electricity and higher overall energy efficiency.
Moreover, import substitution of energy through increased reliance on domestic
resources (renewable and coal) would add to the country's GDP growth.
Oil and gas consumption in domestic (6.655 MTOEs), commercial (2.001 MTOEs) and
transport (18.637 MTOEs) sectors collectively amounted to 27.2 MTOEs in FY201856,
which was more than 3 times the amount of energy consumed as electricity in the
country in equivalent MTOEs of 8.708. Shifting even a small fraction of energy
consumption in transportation, space/water heating and cooking to electricity
(from oil, gas, LPG, etc.) would greatly increase the country's electricity
consumption, thereby lowering the cost of power generation.
124
J NHP RATIONALISATION
It is worth mentioning that for private hydro IPP, the rate for use of water resource
as per the Power Policy 2015 approved by CC! is Rs. 0.425/kWh however, if the same
resource (water) is used by the Federal Government for hydroelectric plant in the
province, the rate shoots up to almost three times to Rs. 1.15/kWh. NEPRA has
approved annual indexation of 5% on the current rate of Rs. 1.10 per kWh from FY
2016 which, if applied, would increase the rate to Rs. 1.273 per kWh for FY 2019-20.
The Committee did not however find any record which shows that the CCI has
approved such indexation over the rate of PKR. 1.10/kWh. Regardless of
nomenclature, essentially it is an issue of water pricing, for which, the formula
generally used globally is based on unit of electricity produced.
Therefore, there is an urgent need to review the situation while learning from
countries with significant hydro generation such as Brazil, China, Canada & India.
In light of the economic strain it is causing, a consensus has to be developed
between stakeholders on a revised and sustainable NI-P formula which the
consumers and the power sector economy can afford.
TRANSMISSION CONSTRAINTS
CPPA-G57 has highlighted the transmission network congestion leading to despatch
of expensive power plants which are lower down the merit order. Therefore, the
Federal Government should facilitate the requisite investments in NTDC's and
DISCOs' network to remove constraints.
57
Power Purchase Price Forecast (FY2019-20) by CPPA-G-G
125
66% PLANT FACTOR FOR RLNG BASED IPPS
The ring-fenced pricing mechanism of RLNG and relatively high price of LNG
imported58 under the term-contracts make the fuel more expensive than domestic
natural gas. Further, due to a continued slump in international LNG market, the spot
prices have dropped to lower than USD 3 per MMBTU59 for March 2020 whereas,
because of these legacy contracts, the consumers will be paying over USD 10 per
MMBTU60.
The preferred option would be price reduction as well as removal of the 66% plant
factor requirement, which will yield substantial savingsol. However, this will require
renegotiating the terms of the LNG supply contract with Qatar. Reducing the
minimum monthly LNG supply quantities by spreading them over a longer period
will also help.
While the supply of imported LNG, after regasification, is through the same gas
distribution network of SNGP and SSGC which carries natural gas from domestic
fields, the pricing of RLNG is ring-fenced i.e., it does not become part of cost of gas
in the formula for determining selling prices for domestic gas.
The major gas producing provinces are averse to RLNG becoming part of the
WACOG as they claim that it would be a violation of the Article 158 of the
constitution, i.e.: "The Province in which a well-head of natural gas is situated shall
have precedence over other parts of Pakistan in meeting the requirements from
that well-head, subject to the commitments and obligations as on the commencing
day".
It is clear that gas usage and pricing are two mutually exclusive subjects and
perhaps the main reason for the Provincial opposition to combining the cost of
RLNG and domestic gas is its potentially negative impact on Gas Development
56 Pakistan imports 800 MMCFD LNG under term contracts of which 600 MMCFD is priced at 13.37% of Brent.
55 11111 V. iiIt Lii ILLIL /1211111/6I WL .1 WIlIclow-onens-tor-oakistan-to-hit-a-low-cost-Ina-iacknot
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126
Surcharge ("GDS")62
. As domestic gas is cheaper, combining it with more expensive
RLNG could reduce the GDS accruing to the provinces. Nevertheless, declining
domestic natural gas supplies and potential imports of cheaper LNG by the private
sector would in any case constrain the provinces' future GDS revenues. The
Government can offer an alternate mechanism offering minimum GDS revenues for
provinces in return for their consent for making RLNG part of WACOG.
Ease the accumulation of circular debt not only in the power sector but also
the one that has started building up in the natural gas sector due to supply of
RLNG to domestic consumers; and
iv.
Resolve the issue of inefficient gas based old GENCO's getting up higher in the
merit order due to availability of cheaper gas.
Achieving meaningful gains in these two areas would require major revamping of
DISCOs' governance structures and investment in infrastructure and human
resources. Improvements are not possible without an element of deterrence for
both the electricity service providers (DISCOs) and consumers to stop perpetuating
the theft and other unlawful activities.
In this regard, amendments to the NEPRA Act in 2018 included a newly introduced
section which empowers NEPRA to administer complaints of theft and over billing
62
GDS = Average Selling Price (local gas) - WACOG - Distribution Margin
127
whereby they can either impose a fine themselves on the entity or file a direct
criminal complaint against an individual involved in the theft. This was a major
procedural change aimed at simplifying the handling of cases of theft and
overbilling:
Some DISCOs also suggested assistance of Rangers to control theft and recovery of
arrears in areas with high losses and less recovery.
The poor performance of distribution sector can be gauged from its billing
recoveries and level of transmission and distribution losses. The following table
63 In terms of section 2 ()ma) "specified" means specified by regulations made under this Act, i.e. regulations are to be
made by NEPRA to give effect to this provision.
128
illustrates how each DISCO cohtributed towards the loss to the sector, in descending
order, which is reflected in the accumulation of circular debt during the last six years
ending June 30, 2019.
F,Inanclal Impact,(2014-2019) 1
DISCOs T840 loss 1 Under Recoveries I Total Disco-wise Accumulated
PKR billion
percentage
QESCO 28.55 204.79 233.34 30% 30%
PESCO 55.33 71.55 126.88 16% 46%
SEPCO 37.53 74.42 11135 14% 60%
HESCO 30.02 60.93 90.95 12% 71%
IESCO 2.18 76.05 78.23 10% 81%
LESCO 39.50 27.01 66.51 8% 90%
MEPCO 18.28 14.51 32.79 4% 94%
TESCO 1.93 18.02 19.95 3% 96%
GEPCO 2.55 16.95 19.50 2% 99%
FESCO 5.75 2.51 8.26 1% 100%
TOTAL Discos 221.62 566.74 788.36 100%
Three options are proposed below for improving the management of DISCOs:
PUBLIC-PRIVATE PARTNERSHIP
129
investors. The shareholding offer can be by way of additional capital issue so that
the proceeds stay in the DISCOs for investment.
Government can continue to retain wire business only. Under this model, the non-
risky business will remain with Government in shape of assets whereas the risky
business requiring better management will be passed on to the private sector.
Since the DISCOs are deemed to be suppliers till April 2023, this would also be a
good interim measure before transitioning to a completely independent supply
segment in the power sector, driven by market driven supply and demand.
Turkey is a good example of this model where the wire business is with the
government and commercial activities are passed on to retailers and bulk suppliers.
The potential downside of this model is continued dependence on the government
for infrastructure improvements, planning and decision-making.
Along with the two options recommended above, the Federal Government should
consider breaking down DISCOs into corporate units with a smaller and more
manageable service territory. This would entail a de-merger of the ten DISCOs into
such number of companies as are suited to the needs of their consumer base.
130
465. The government has pledged performance-based management of DISCOs, as part
of energy sector policies65
conveyed to the IMF, i.e.: 'To improve efficiencies and
collections the government will sign performance-based contracts with all DISCOs
by end-January 2020. The contracts will contain KPIs for improvements in collection,
reductions in losses, and meeting the regulatory timelines for petitions submissions,
with mechanisms to reward good performance and/or compensate for shortfalls.
DISCOs will submit quarterly performance reports to NEPRA and will be published on
NEPRA's website.'
p
1 466. The operational independence of DISCOs is not possible without a strong financial
position. As per the available annual accounts of seven DISCOs for FY2018, five of
them had net negative equity balances.
r- 467. Historically, DISCOs' tariff determinations and their notifications by the Federal
1
, Government were delayed on account of political and legal constraints.
Consequently, the financial statements of the DISCOs were unreflective of their true
and fair financial position. While their costs were reflected in the periods they were
incurred, the revenues were distorted due to delays in determination and/or tariff
notification.
468. Delayed tariff notifications result in large prior year adjustments in subsequent
periods' tariffs and are then reflected in DISCOs' financial statements.
Total Equity
-20,402
GEPCO
5,863
HESCO -31,160 -126,017
IESCO -27,337 14,597
MEPCO -33,825 -64,811
PESCO -42,986 -227,666
_
QESCO -27,224 -78,547
131
A weak financial position impairs the DISCOs' ability to make the requisite
investments for lowering T&D losses, reduce the number of overloaded
feeders/transformers and undertake network expansion, all of which can help
towards alleviating the circular debt problem. Further, a fragile financial position66
makes it very difficult to privatise the DISCOS, especially the weaker ones.
As noted earlier, a growing number and amount of running defaulters raises doubts
about whether they represent disguised T&D losses (excess billing) or genuine billing.
A 2004 WAPDA approval allowed HESCO to adjust excess billing without credit of
units and the company apparently still continues to use it. There is a need for
transparency in billing by closing any loopholes providing room for fictitious billing.
Moreover, reputable chartered accountancy firms should be engaged to carry out
detailed scrutiny of receivables from running and permanent defaulters to
ascertain their recoverability.
RESOLVING QESCO
The two main issues with QESCO are high technical losses and very low bill recovery
rate. The technical loss, estimated at about 20% (out of total T&D loss of 23.6%), is
primarily because of a vast geographical spread of the company's network
supplying relatively small quantity of electricity. QESCO's units purchased to
network ratio is about 44% lower than the average of all DISCOs.
66
Negative equity balances, large unfunded pension obligations and large receivables from running/disconnected
defaulters
132
Table 63 - QESCO Units Purchased to Network Ratio Relative to All DISCOs
NetWork Size (NM) Units Purchased Units/Network T&D Loss
HT LT Total (GWh) Size (KWh/KM)
LESCO 29,309 15,001 44,310 24,338 549,277
GEPCO 13.2%
23,234 18,541 41,775 11,100 265,711 9.9%
IESCO 25,458 27,041 52,499 11,838 225,488
FESCO 8.9%
41,262 27,154 68,416 14,970 218,807 9.8%
PESCO 36,678 45,121
14,427 81,799 176,375
MEPCO 37.1%
76,057 49,992 126,049 19,367
153,644 15.8%
HESCO 28,305 15,005 43,311 5,557 128,300
SEPCO 29.5%
24,618 13,340 37,958 4,412 116,222 37.0%
QESCO 39,712 15,803 55,515 6,257 112,711
TESCO 23.6%
10,212 6,278 16,490 1,821 110,412 12.0%
TOTAL 334,844 233,277 _
568,121 114,086 ?no 21, •• OIA •
J
14170
This could be aimed especially in the area of agriculture tube well where solar
power is promising to become a cheap and viable solution to meet the agriculture
sector needs, off the traditional grid. A cost and benefit analysis could measure the
benefit of providing cheap solar power at affordable terms and conditions. This
could include concessional financing for the procurement of solar tube wells.
Additionally, alternative solutions should be explored for meeting the water needs
of the province's irrigation and drinking water to reduce the reliance on tube wells.
_ REGULATORY AND FISCAL INEFFICIENCIES
476. Three observations can be made about current consumer-end electricity tariffs:
a. The overall tariffs are high;
133
Average Tariff excluding Tax (Dec-2019) Average Tariff including Tax (Dec-2019)
25 71 7 35
19.7 30
20 16.3 25 20.1
13.4
S 15 20
pe
x 10 gd 15
O.
4.4 10
5 5
0 a 111 II 0
°'
t., Ta Ira
@ja 74 a.
as
= g 0>
01 .
ei
g
,
a Excluding Tax: Dec-2019 Including Tax: Dec-2019
Data Source: PEPCO i Data Source: PEPCO
477. Large cross subsidies (especially in the domestic consumer category) and heavy
tax incidence are contributing to grid defection by the industrial sector and
solarisation by commercial and high-end domestic consumers. There is therefore a
need for rationalisation of consumer end tariffs to raise demand for grid electricity.
478. Further, the following contributes significantly to the build-up of circular debt:
political considerations;
134
Under-budgeting of tariff subsidies and their slow disbursements; and
Tax anomalies.
In this regard, the NEPRA Act requires NEPRA's input into the National Electricity
Policy and National Electricity Plan under section 14A, and conversely, NEPRA is to
consider the Policy and the Plan in its regulatory objectives.
r- -
135
SECTION 3 - FUTURE ROADMAP - COMPETITIVE POWER
MARKETS
livdel
NTDC
GENCO
IPP
4,3 E
Generation w
3
Nuclear
The guarantees given by the State in a single buyer model can undermine the
government's creditworthiness and macroeconomic stability;
68 Lovei, The Single-Buyer Mod& : A Dangerous Path toward Competitive Electricity Markets"
( http://siteresources.worldbank.org/EXTFINANCIALSECTOR/Resources/ 282884-1303327122200/225Lovel-1211.pdf).
136
Since a single buyer system is usually state-
owned/dominated, it is not driven
by profit motives and instead finds it difficult to take tough decisions against
inefficiencies because of socio-political pressures. As a result, there is little or no
incentive for distribution companies to increase collection;
There is a higher pressure from lobbies in a single buyer model to delay the
transition by government into a competitive electricity market model.
483.
As also highlighted in other parts of this report, unfortunately, Pakistan has suffered
from each of these disadvantages.
In a competitive market on the other hand, the transactions are structured in a way
that the payment obligations are spread out over multiple buyers and sellers. A
structured market itself contains checks and balances, such as the settlement
guarantee fund in neighboring Indigo as well as in the US and various European
countries. This supports the systemic integrity of the market in case of major defaults
or liquidity constraints.
Jr
69
acorrapjgSeaalDocument/03 (2 20181EX7,20Rules,m1
137
HIGH COST OF ELECTRICITY
487. Regionally, Pakistan has the highest cost of electricity in all three major consumer
categories:
This has had a cyclical impact — policies designed only to incentivize generation by
offering long term guaranteed returns ended up reinforcing the single buyer model
because with guaranteed returns, competition was not an option. The resulting lack
of competition in turn allows leverage to current players in the generation segment
of the power markets, who prefer status quo to transitioning out of the current
structure.
138
In a competitive power market on the other hand, cost reductions, improved
efficiencies, payment capacity of consumers etc. of themselves drive the demand
and supply of electricity, allowing for a financially more viable power sector overall.
r- LACK OF COMPETITION
The lack of competition in the generation and distribution/retail segments has
created problems in the entire supply chain of electricity. On the generation side, it
has led to the development of tariff regimes (either cost plus or upfront tariff
regimes) which are more investor centric than consumer oriented. The result is
excess profitability by generation companies on account of lack of regulatory
oversight and faulty pricing models. On the distribution side, the lack of competition
translates into inefficient service delivery whereby DISCOs are burdening consumers
with high losses, under recoveries and theft.
139
LOW RECOVERIES & HIGH LOSSES IN A REVENUE BASED DISTRIBUTION
MODEL
The current business model for DISCOs is revenue capped by NEPRA, and any
differential in revenue on account of variables inter-alia, low recoveries, high losses,
low demand, etc. is neither penalized nor incentivized, therefore minimizing the
room for efficiency gains and ultimately causing high electricity tariffs. Such models
are generally unsustainable in the scenario of low electric load growth and high
distributed energy penetration which is prevalent in Pakistan.
The DISCOs' revenue declines when demand for electricity drops, however, its costs
remain unchanged, ultimately overburdening the end consumers. It is therefore
necessary to shift to a profit-oriented business model aimed at enhancing profits by
increasing the consumer base, reducing technical and administrative losses,
ensuring recoveries and increasing reliability of their services.
Further, a component of the consumer end tariffs is the Aggregate Technical &
Commercial losses allowed by NEPRA in determining the revenue requirements of
a DISCO. The actual losses incurred are however much higher than the allowed
losses, and the difference between the two ends up translating into inadequate
recovery of the revenue requirement of distribution companies. A summary of non-
recoveries and T&D losses by DISCOs is depicted below:
Distribution Companies
Billing, Recovery and T&D Losses
2019
350,000
300,C00
25 0,C00
200,600
2
iso.0,0
2
50,060
140
This shortfall in revenue requirement of DISCOs translates into a higher tariff request
from NEPRA by the DISCO in subsequent years.
SUPPRESSION OF DEMAND
Demand forecasting is a key variable in the entire power supply chain and is vital
to planning supply additions which usually take a long lead time. In the past, our
demand forecasting function had been weak and didn't capture ground realties
like technology advancements, conservation measures, etc. This led to over
estimation of electricity demand resulting in mismatch between GoP policies and
actual country needs causing an induction of surplus installed capacity.
500. The demand forecasting function tends to be much more evolved in competitive
power markets on account of the financial implications to various participants in
the power market.
NON-
COMPLIANCE OF COST OF SERVICE-BASED TARIFFS
Cost of service-based tariff is the true cost of supplying electricity to a certain class
of consumers In Pakistan. Non-compliance of cost of service-based tariffs has led to
inefficiencies and disturbed the economic viability of the sector. This leads to the
discriminatory treatment among various classes of consumers. A tariff structure in
which true costs are not passed on to consumers causes inefficiencies and
misguides investment decisions in the overall supply chain of electricity.
In competitive markets, the State is largely unburdened with bearing the cost
differential between regulated end-consumer tariff and affordable end-consumer
tariff, since its role becomes limited to providing an enabling environment in which
the power sector players can operate efficiently and profitably while minimizing
market abuse by the participants.
C-
141
Overcoming the Single Buyer Crisis
In order to permanently address most of the financial and technical issues of
Pakistan's power sector, a structural and regulatory reform is required. Such reform
has been attempted since the mid-90's with the unbundling of WAPDA,
establishment of NEPRA, creation of DISCOs, and most recently, the separation of
CPPA-G from NTDC.
This last reform was originally proposed as part of a program aimed at enabling the
ten DISCOs, instead of NTDC, to start purchasing electricity, i.e. a multi-buyer
market. However, subsequently, the Federal Government tasked CPPA-G as the
sole purchase agent of all DISCOs.
This could be a reason why the Federal Government has been largely unsuccessful
in driving down the cost of electricity, as well as why the Federal Government
resisted the transition to competitive markets.
This transition is, however urgently required, and the role of the State in the power
sector has to be limited to policy, planning and broader regulation. If we are to
permanently address our power sector issues, the Federal Government, the
Provincial Governments, and NEPRA will have to engage private sector investment
and create a competitive environment among different players to enable them to
become the drivers of efficiency and lowered electricity costs.
142
THE MOVE TO COMPETITIVE ELECTRICITY MARKETS
509. In April 2018, the Parliament introduced major reforms in the NEPRA Act, with a view
to providing the regulatory framework within which NEPRA and the Federal
Government could work towards establishment of a multi-buyer competitive
electricity market. The intent of the Parliament was demonstrated through the
amendment to the preamble of the Act which now reads:
Responsibility
De-License Generation
Generation companies will continue to comply with minimum
technical and safety standards but will establish a plant on their Section 14(13)(5) - Federal
own risk. Government to notify plan for
Eventually generation tariffs by NEPRA will be replaced with market de-licensing by April 2023
driven tariffs, subject to checks against overpricing by NEPRA.
Generation companies can,
sell to other licensees, e.g.
transmission companies, market traders, distribution companies
etc., however they cannot sell to the end consumer without
obtaining a supply license (explained below).
Set up lnde endent System Operator "SO"
A SO oversees the economical and continuous transportation of
electricity from generation till consumption, in accordance with Section 23G - Federal
the NEPRA approved grid code. Government, either on its own
An independent SO will also be able to independently identify and or on the recommendation of
flag system constraints at the transmission and distribution level. NEPRA, to make rules for grant
Section 1(3) of the Act makes this provision effective in April 2023, of system operator license,
but Federal Government can notify an earlier date for this as well. including minimum solvency
and technical and human
resource requirements.
143
,
Segregation of Distribution and Retail Function (Supply)
A distribution company in Pakistan undertakes two functions: Section 23E - Federal
Non-risky: Management of distribution network: and Government, either on its own
Risky: Retail of electricity to consumers (supply function), motion or on the
The Act requires two separate licenses for each function, recommendation of NEPRA, to
The supply license is non-exclusive, i.e. multiple suppliers possible in make rules laying down
one territory for greater competition leading to higher efficiency. eligibility criteria for grant of
Supplier can purchase electricity directly from a generation electricity supply license,
company, through an electricity trader or from a platform, including minimum solvency
enabling them to offer different packages to consumers, which in and technical and human
turn will be an incentive for generation companies to produce resource requirements.
cheaper electricity.
Distribution companies are deemed to be suppliers till April 2023, Section 50(2) - NEPRA to update
i.e. DISCO's can in the first instance outsource their retail business and convert relevant standards
operations for improved efficiencies. and procedural requirements
The supply license provisions became effective immediately with from rules to regulations.
amendment, i.e. supply functions can commence as soon as the
legal framework is put in place by the Federal Government and
NEPRA.
Opening the supply market will leave only the non-risky aspect of
distribution with the Government and in that sense is an alternative
to privatization.
144
The market is able to withstand lobby pressures; and
The market can independently focus on competition which and technical and human
resource requirements.
brings efficiency and help provision of least cost electricity to
consumers.
MO transacts business under a regulated code, therefore Section 50(2) - NEPRA to update
providing certainty for investors and consumers alike. and convert relevant standards
Section 1(3) of the Act makes this provision effective in April 2023, and procedural requirements
from rules to regulations.
but Federal Government can notify an earlier date for this as well.
H
511. The following diagram broadly sums up the impact of the new market structure
under the Act:
Consumer
to,da ,g7L40.0
Electricity Row
— _0. System Coordination
Sale/Purchase
512. Under the new model, the physical infrastructure of NTDC, as a natural monopoly,
can continue to be owned by the Federal Government. Insofar as the DISCOs are
concerned, the law segregates their functions as follows:
i.
Distribution: Ownership, operation, management or control of distribution
facilities for the movement or delivery to consumers (section 2(v) of the NEPRA
Act)
145
It is important to note that after April 2023, the existing DISCOs will not be able to
undertake supply functions, unless a separate corporate entity is established and
licensed. 71 This will automatically segregate the balance sheet of the DISCOs into
risky (supply) and non-risky (distribution) activities. The result is that the risk of the
Federal Government on the balance sheets of the DISCOs is minimized in the
distribution function.
Further, the law allows multiple suppliers in a service territory in order to encourage
market driven efficiencies, therefore the risk in the retail/supply is spread across
multiple entities.
Even for the service territories where there are non-paying consumers, the balance
sheet of the DISCOs will be strengthened by the segregation of the supply function,
and their financial ability to improve network would be enhanced. However, in
these areas the Federal Government may initially continue to take risk in the supply
function till such time that the supply market is fully developed there. For this
purpose, the Federal Government will have to propose incentives and support for
the development of a supply segment in difficult service areas, including continued
subsides to certain consumer classes, strengthening network availability, etc.
Following through on the legislatively mandated plan would therefore reduce the
financial, social and political risks which the Federal Government has been bearing
under the existing power policies and would also promote much needed efficiency
and liquidity in the power sector. The law itself provides a mechanism ensuring this,
as explained in the following paragraphs.
71 The law requires different conditions of licenses for distribution (section 20) and supply (section 23E), including
minimum capital requirements and HR capacity.
146
and physical infrastructure in a structured, implementable and accountable
manner.
Provided that in the development of policies under this section, the Federal
and assistance from the Authority as may be required. Government may seek such input
(2) The policies referred to in sub-section (I) shall provide for, inter alto-
development
of systems based on optimal utilization of resources such as cod, natural
substances or materials, hydro and renewable sources of gas, nuclear
energy;
development of efficient and liquid power market design:
integration of national
and provincial transmission systems:
special provisions for ensuring the development of a
sustainable renewable energy market with a
dedicated and gradually increasing share in the electricity power sector; and
any other
matter pertaining to the development reform, improvement and sustainability of the power
sector.
(3) The Federal Government may
either on its own motion or the recommendation of a Provincial
Government and, subject to the approval of the Council of Common
referred to in sub- section (7), Interests, review or revise the policies
147
NEPRA to provide support and input in the development of the Policy and Plan
and to tie in its regulatory objectives and strategy with the approved Policy and
Plan.
Hi. Lack of communication and coordination between the Federal and the
Provincial Governments because of which a National Electricity Policy and
National Electricity Plan under section 14A of the NEPRA Act have not yet been
approved.
Lack of harmony between the rules and regulations of NEPRA with the newly
amended NEPRA Act. NEPRA was to bring the rules and regulations made
before 2018 in line with the amendments, which has not yet been done. The
legal framework for licensing of system operator, traders, suppliers, market
operator, and de-licensing of generation companies is therefore not yet in
place.
A good step forward is the Competitive Trading and Bilateral Contract Market
Model ("CTBCM Model") prepared by CPPA-G which has been approved by
NEPRA in December 2019. In order to ensure a smooth transition to a multi-
buyer market, the following aspects require further deliberations:
The CTBCM model has been prepared under rules which were made prior
to the passage of the Act. The proposed plan in this model therefore now
148
needs to be endorsed in terms of section 14A of the NEPRA Act, i.e. by the
CCI at the policy level and the Federal Cabinet at the planning level.
The CTBCM model proposes that PRIB and AEDB, which are both statutory
bodies, should undertake the auction function as IAAs as registered
persons under the NEPRA Act. However, section 24 of the NEPRA Act states
that:
CPPA-G has prepared a roadmap for implementation in the next two years to
operationalize the market. The same needs to be discussed by all power sector
institutions with a view to reach an agreement on the plan of actions required for
competitive power market set-up in the country in light of the applicable legislative
framework.
72 Section 25A- Registration, Any person providing electric power services, other than generation under Chapter NA or an
electric power service requiring a license under this Act, shall be registered with the Authority in the manner and subject
to such conditions as may be prescribed.
1 49
r-1
522. Accordingly, it is proposed that:
Undertake the functions of PPIB and AEDB with respect to existing PPA's;
Hi. The first proviso of section 50(1) of the Act mandates that:
150
Generation,
Transmission and Distribution of Electric Power (Amendment)
Act, 2017. "
It is therefore proposed that NEPRA may initiate this exercise at the earliest in
order to ensure that the requisite regulatory framework is in place for the
operations of competitive power market.
151
SECTION 4 - IMPLEMENTATION PLAN
523. The purpose of this section is to consolidate recommendations in Sections 1, 2 and
3 of this Report, and propose an action plan to the Federal Government for ensuring
effective execution of the recommendations. Specific action points are outlined
with the relevant entity which should be assigned responsibility. Overall responsibility
to monitor progress of this plan should be with the Power Division, being the
authorized arm of the Federal Government. This will require strengthening of the
Power Division in the manner proposed below.
Recommendations
Shift from USD to PKR based tariff for all IPPs 3 Change in Policy Power Division
152
CIRCULAR DEBT AND DISTRIBUTION INEFFICIENCIES
Mechanism
Responsibility
Circular debt stock reduction/elimination and reduction of finance
cast in line with Committee's recommendations Cabinet approval of measures for one-time
6 reduction with eventual payback from Power Division/Finance
Debt rep:Ailing of public sector power plants (WAPDA, PAEC, measures implemented by Power Division Division
GENC05, 4 x 1200 MW RLNG based plants', renewable, CPEC and
coal-based ro acts 3 Negotiate extension of project debt repayment
period to 25 years Power Division
Reduce finance cost on long term project debts, working capital and _
LPS
3 NEPRA through tariff review
NEPRA
Moratorium on new plants, delay and reconsideration of upcoming
plants and non-renewal of plants reaching expiry 1 Cabinet direction to NEPRA, PPIB, AEDB and
CPPA-G Power Division
Novetion of PPM to KB instead of ICE setting up new 900 MW RLNG
and 700 MW coal-based • ts
Conducting requisite technical studies for
ICE to submit timeline for retiring/mothballing old 1200 MW Bin identifying solutions aimed at a) integration of
Qasim !ant 6
ICE and NTDC Systems, b) augmenting supply
inte raUon of NTDC and KE S terns to ICE and c) novation of PPM of IPPs (coal, Power Division/KR
Rollout of a comprehensive plan for electrification of domestic energy nuclear, wind) located in the south.
use for
cooking, space heating, water heating and electronic vehicles
for use in ublSit_N•
tuts rt 6 Preparation and execution of plans and
policies
NEECA /Planning Division
RLNG contract renegotiation and inclusion in WACOG Cabinet approval for re-negotiation and SC
3
inion on interpretation of Article 158 of the
Rationalization of natural gas tariff for onstitution of Pakistan, 1973 Petroleum Division
captive power plants to
incentivize their shift to the public grid and for GENCOs to be
a prepriately utilized in merit order 1 Cabinet Approval
Petroleum Division
Strengthen management of DISCOs, PEPCO, NTDC and PHPL
Restructure balance sheet of DLSCOs Cabinet Approval
Power Division
Public private partnership/separation of wire and commercial Conversion of deferred credit into equity
Power Division
business and possible breakup of DISCOs into smaller service Identification of passible PPP
territories 6 collaborations/initiation of requisite legal PPP Authority/
Payment of outstanding subsidies and devising a mechanism actions under NEPRA Act Privatisation Commission
for
sharing of future subsidies with provinces with at source deductions CCI approval on the recommendations of
from amounts transferred under NFC 6 committee comprising Power Division,
Finance Division and Law Division Finance Division
Subcontracting recovery of receivables, private sector
NEPRA Act - Supply provisions
Power Division /NEPRA
Reform QE5C0 through distributed generation and micro grids Conduct feasibility studies for distributed
12 generation and micro grids (based on
I indigenous natural gas and renewabies) Power Division
, Solutions for QESCO for water supply for irrigation and household
consumption Conduct feasibility studies for finding optimal
12 solutions for meeting Balochistan's water
needs Ministry of Water
Rationalization of existing NHP
Cabinet approval
Power Division
153
FUTURE ROADMAP - COMPETITIVE POWER MARKETS
Recommendation
In this regard, the Power Division of the Ministry of Energy is the key administrative
unit of the Federal Government which is responsible for matters related to the
development of power resources of the country and is therefore most suited to take
this responsibility and ensure the performance of these tasks.
In this regard, the following outlines a proposed restructuring of the Power Division
wherein they will be enabled to hire and utilize in-house expertise.
154
Current Organogram of Power- Division
528. A closer look at the organogram of the Power Division
73 shows that the current
organization structure is geared towards an entity-based structure and not function
based. This is despite the fact that different kind of specialized knowledge is
required to manage the national power policies, plans and sector, which includes
expertise in finance, legal, energy economics, etc.
IFederal Minister I
Minister of State
Federal Secretary I
Addition el Secretary I
SO
OS (NTDC) os (Day)
II DS (Admit) OS (Pc)
(Entitles)
SO
I itrons
so j
SO
I o (AdSrnn) I
SO
(IFFs)
(CoSCOs) (GENs)
I (General) I
SO
(PF)
SO SO
C&C) (Tariff)
SO I so I
4Law) (Pretn)
Network Administrator I
73
This organogram is from the year 2017
155
The proposed organogram of the 2017 restructuring plan is:
Miffitier
Secretary
Additional Additional
Secrelary I Secretary II
Section Officer
Record Chicor
(CC)
Network
Admffildmtor
Policy experts and energy economists responsible for drafting the national
electricity policy and plan;
156
Lawyers providing in-hbuse siipport in managing the sector's contracting
matters, litigation, arbitration, etc.; and
This restructuring is not new to the Federal Government. Currently, the Privatization
Commission is organized along similar lines, staffing experts from different areas
having sector-specific knowledge who can manage complex privatization
transactions.
Moving forward with a renewed vigor to address the issues faced by the nation's
power sector, approving this implementation plan as well as strengthening and
restructuring of MoE (Power Division) may be the most important steps in the right
direction.
157
SECTION 5 - IPP WISE REPORTS
Background
Date of Incorporation December 1, 2005
Ownership Structure Subsidiary of Attock Oil Company Limited, UK
Ultimate parent is Bay View International Group S.A.
Size of Plant 165 MW
Location of Plant Morgah, Rawalpindi
CoD March 17, 2009
Term of PPA 25 Years
Details of Tariff
Tariff Petition Submitted on November 2005
Tariff Petition Admitted on June 2006
Tariff Granted on September 4,2006
Tariff Control Period allowed 25 years
Project Cost claimed USD 150.034 million
Project Cost allowed USD 148.601 million
IRR Allowed USD based equity - 15%
EPC 126.600 million
Import Duties etc. 6.510 million
Breakdown of Emergency Spare Parts 1.890 million
Project Cost Mobilization Cost 0.910 million
allowed Project Development Cost 2.050 million
(USD) Admin and Utilities 0.750 million
Financing Fees & Charges 2.494 million
Interest During Construction 7.396 million
Tariff Determination COD Determination
Capital 04-09-2006 30-07-2009
Structure and Equity i
29.720 31.024
Project set-up Total debt 118.880 124.095
cost (USD Total Project Cost 148.600 155.119
million) 80:20 80:20
Debt to Equity Ratio
Details of Tariff Determination COD Determination
Project Costs 04-09-2006 30-07-2009
EPC, total
project cost EPC Cost 126.600n 122.148
and changes EPC Cost — break-up hi currencies - Euros US$105.50
on account of Other costs 14.605 13.809
foreign Total Capital Cost 141.543 135.957
currency Interest During Construction (IDC) 7.396 19.162
fluctuation? Total Project Cost 148.601 155.119
(USD million) USD I EURO parity rate 1.20 1.4183
Output of the plant 156.138MW 156.181MW
74
As the timing of exact payment to contractor was unknown, therefore, adjustment for the relevant foreign currency
fluctuations allowed.
15 The Authority allowed adjustment in EPC cost due to foreign currency fluctuation
158
REVIEW OF PROFITABILITY AND DIVIDENDS
534. To determine the profitability and dividend history of AGL, the financial statements,
documents provided by NEPRA, PPIB and CPPA-G and the relevant publicly
available information were reviewed for the period March 17, 2009 till June 30, 2018.
Details are as follows:
535. A comparison of Adjusted Profits with allowed regulatory returns during the period
July 1, 2010 to June 30, 2018 revealed that AGL has earned an excess profit of
Rs.13.81 billion. Detailed working of the excess profit is as follows:
159
DETAILS OF SAVINGS IN FUEL COST
536. The fuel cost allowed as per tariff determination (provided by CPPA-G) exceeded
the fuel cost reported in the financial statements by an amount of Rs.8.87 billion,
which has ultimately contributed towards an excess profit of Rs.13.81 billion, as
presented below:
160
Contribution of Savings in O&M Expenses to Total Excess Profits
O&M Expenses allowed
Rs.12.15 billion
O&M Expenses incurred
Rs.8.33 billion
Difference in Allowed and Incurred O&M
Expenses Rs.3.82 billion
Details of Savings in O&M Expenses:
Year Net Delivered Total Variable
Energy O&M Total Fixed O&M Total O&M As per Difference
Units in Billion Financials (Savings)
FY 2009-10 1.230 0.657 0.250
FY 2010-u 1.203
0.906 0.392 0.514
0.805 0.327
FY2011-12 1.132 0.541
1.172 0.860 0.591
0.362 1.222
FY 2012-13 1.255 0.912 0.310
1.006 0.388
FY 2013-14 1.394 0.705
1.243 1.083 0.689
0.429 1.512
FY 2014-15 1.209 0.880 0.632
1.071 0.442
FY 2015-16 1513 1.248
1.179 1.079 0.265
0.454 1.533
FY 2016-17 1.135 1.200 0.333
1.068 0.469
PY 2017-18 1.537 1.384
0.912 0.905 0.153
0.491 1.396
Total FY 2010-2018 10.539 1.071 0.325
8.534 3.612 12.146 8.335 3.811
161
ADDITIONAL PROFITABILITY ON ACCOUNT OF MISMATCH IN DEBT
REPAYMENTS
SUMMARY OF FINDINGS
1 62
Liberty Power Tech Limited
fl Back ound
Date of
September 13, 2007
Inco oration
Ownership
Structure Subsidiary of Liberty Mills Limited
Size o Plant 200 MW
Location o Plant Faisalabad
CoD
Term o PPA Januar 13,2011
25 Years
Details o Tan
Tani Petition Submitted on
November 2007
Ta-i Petition Admitted on
November 2007
Tan; Granted on
Tan Control Period allowed Februar 28, 2008
25 ears
Pro'ect Cost claime
Pro'ect Cost allowed USD 150.034 million
IRR Allowed USD 148.601 million
USD ased e ui - 15's
Breakdown of EPC
Project Cost 0 er Costs 197.961 million
allowed 28.002 million
(USD) Interest Dunn: Construction
Capital 13.848 million
Structure Tariff Determination
COD Determination
and Project E • ui 28-02-2008 17-08-2011
set-up cost Total debt 59.953
60.06
(USD 179.858
Total Pro'ect Cost 180.18
million) Debt to E ui Ratio 240.24
Details of
EPC, total Tariff COD
Project Costs
project cost Determination Determination
and changes EPC Cost 28-02-2008 17-08-2011
on account of o er costs 197.961 185.65
foreign 28.002
currency Interest Dunn: Construction IDC 28.88
Total Pro'ect Cost 13.848
fluctuations 239.811
(USD USD EURO ari rate 240.24
Output of the plant 1.20 1.4582
million) 200MW 196.139MW
163
r 1
Review of Profitability and Dividends
13.1.2011 till 30.6.2018
Capital Injected by Sponsors Rs. 5.05 billion
Allowed Regulated Profit Rs.7.52 billion @15% USD equity IRR
Profit Recorded F12010 to F12018 Rs. 23.97 billion
Profit after adjustment Rs. 19.84 billion
Excess Profit Rs.12.32 billion (Allowed Regulated Profit - Profit after
adjustment)
Amount withdrawn from Profits as Rs. 17.89 billion
Dividend
Equity Payback after CoD 2 -3 years
is as follows:
Excess return 0.504 1.182 1.366 2.164 2.100 2.065 1.394 1.544 12.319
164
DETAILS OF SAVINGS IN FUEL COST
540. The fuel cost allowed as per tariff determination (provided by CPPA-G) exceeded
the fuel cost reported in the financial statements by an amount of Rs.4.33 billion,
which has ultimately contributed towards an excess profit of Rs.12.32 billion, as
presented below:
165
Contribution of Savings in O&M Expenses to Total Excess Profits
O&M Expenses allowed Rs.12.88 billion
O&M Expenses incurred Rs.7.34 billion
Difference in Allowed and Incurred O&M Rs.5.54 billion
Expenses
Details of Savings in O&M Expenses:
Net Delivered Total Variable As per Difference
Year Total Fixed O&M Total O&M Financials (Savings)
Energy O&M
Units in Billion Its. in Billion
FY 2010-11 0.745 0.564 0137 0.700 0.254 0.446
FY 2011-12 1.068 0.857 0.378 1.235 0595 0.640
FY 2012-13 1.438 1.283 0.394 1.678 0.783 0.895
FY 20 14 1520 1.449 0.424 1.874 1.116 0.758
FY 2014-15 1.515 1.472 0.473 1.945 0.879 1.066
FY 2015-16 1.250 1.253 0.489 1.743 1.032 0.711
FY 2016-17 1.340 1.383 0,504 1.887 1.161 0.726
FY 2017-18 1.176 1.284 0.531 1.815 1.524 0.290
Total FY 2011-2018 10.051 9.546 3.330 12.876 7.343 5.533
166
ADDITIONAL PROFITABILITY ON ACCOUNT OF SHORTFALL IN INVENTORY
SUMMARY OF FINDINGS
r-•
167
Nishat Chunian Power Limited
Background
Date of February 23, 2007
Incorporation
Ownership Subsidiary of Nishat (Chunian) Limited
Structure
Size of Plant 200 MW
Location of Plant Near Lahore
CoD July 21, 2010
Term of PPA 25 Years
Details of Tariff
Tariff Petition Submitted on January 2007
Tariff Control Period allowed 25 years
Project Cost allowed USD 203.841 million
IRR Allowed USD based equity - 15%
Breakdown EPC 160.170 million
of Project Other Costs 29.027 million
Cost allowed
(USD) Interest During Construction 14.644 million
Capital Tariff Determination COD Determination
Structure 15-01-2007 31-12-2010
and Project Equity 50.960 47.481
set-up cost Total debt 152.881 189.925
(USD Total Project Cost 203.841 237.406
million) Debt to Equity Ratio 75:25 80:20
Details of Tariff COD
EPC, total Project Costs Determination Determination
project cost 15-01-2007 31-12-2010
and changes EPC Cost 160.170 185.810
on account of Other costs 29.027
foreign Interest During Construction (IDC) 14.644 29.587
currency Total Project Cost 203.841 237.406
fluctuations USD /EURO parity rate 1.20 1.4183
(USD Output of the plant 200MW 195.722MW
million)
168
Review of Profitability and Dividends
21.7.2011 till 30.6.2018
Capital Injected by Sponsors Rs. 3.67 billion
Allowed Regulated Profit
Profit Recorded FY2011 to FY2018 Rs.6.52 billion @1570 USD equity IRR
Rs. 21.51 billion
Pro 1 a ter ad ustment Rs. 15.82 billion
Excess Profit Rs.9.30 billion Allowed Regulated Profit - Profit after
ad'ustment)
Amount withdrawn from Profits as Rs. 12.95 billion
Dividend
Pa back er CoD 2 - 3 ears
Description 2018 2017 2016 2015 2014 2013 2012 201 Total
Accounting Profit Before Tax 3.406 2.998 2.756 3.090 2.901 2.713
Depreciation 2.016 1.626 21.507
1.066 1.153 1.171 1.142 1.161 1.103 0.955 1.255 9.006
Debt Service Cost (2.604) (2.481) (2.445) (2.675) (2.645) (2.416) (2.684)
Finance Cost Long Term (2.90) (20.85)
0.584 0.742 0.938 1.388 1.554
Cost of WC as CPPA 1.769 2.246 2.345 11.567
(0.190) (0186) (0.199) (0.264) (0.267) (0.249) (0.298) (0.32) (1.974)
LPS Energy Purchase Price (0.403) (0.281) (0.304) (0.330) (0.324) (0.606) (0.834)
LPS Capacity Purchase Price (0.45) (3.530)
(0.173) (0.102) (0.040) (0.339) (0.227) (0.351) (0.231) (0.09)
Finance Cost Short Term 0.462 (1.549)
0.350 0.281 0.497 0.368 0.655
Capitalized Spares 0.834 0.595 4.042
(0.464) (0.556) (0.385) (0.298) (0.470) (0.040) (2.214)
Donation 0.005 0.085 0.086 0.035 0.051 0.004 0.000 0.002
Other Income (0.036) 0.268
(0.036) (0.028) (0.029) (0.086) (0.156) (0.034) (0.05) (0.449)
Adjusted Profit as Per F.S 1.654 1.685 1.831 2.217 2.015 2.424 1.971
Allowed Regulatory Return 2.026 15.824
0.930 0.893 0.889 0.859 0.860 0.734 0.661 0.696 6.522
Excess return 0.724 0.792 0.942 1.359 1.155 1.691 1.310 1.329 9.302
169
DETAILS OF SAVINGS IN FUEL COST
The fuel cost allowed as per tariff determination (provided by CPPA-G) exceeded
the fuel cost reported in the financial statements by an amount of Rs.3.02 billion,
which has ultimately contributed towards an excess profit of Rs.9.30 billion, as
presented below:
170
Contribution of Savings in O&M Expenses to Total Excess Profits
O&M Expenses allowed
Rs.12.05 billion
O&M Expenses incurred
Rs.7.04 billion
Difference in Allowed and Incurred O&M
Expenses Rs.5.01 billion
Details of Savings in O&M Expenses:
Year Net Delivered Total Variable
Energy O&M Total Fixed O&M As per
Total O&M Difference
Units in Billion Financials (Savings)
FY 2010-11 1.452 0.807 0.336
1.073 0.417 0.725
0.773 0.351
1.283 1.028 0.320
0.390
1.260 0.465
1.415 1.185
1.231
0.943 0.771
1.316 1.215 0.803
0.515
1.099 0.631
1.068 0.541
Total F1' 2011-2018
8.468 0.508
3.582
5.013
171
ADDITIONAL PROFITABILITY ON ACCOUNT OF SHORTFALL IN INVENTORY
Shortfall in Inventory
Inventory Level Required by NEPRA 27,885 tonnes
Average Quantity Maintained 12,910 tonnes
Benefit of Maintaining Lower Inventory Levels Rs.0.57 billion
SUMMARY OF FINDINGS
172
Nishat Power Limited
173
Review of Profitability and Dividends
9.6.2010 till 30.6.2018
Capital Injected by Sponsors Rs. 3.54 billion
Allowed Regulated Profit Rs.6.17 billion @15% USD equity IRR
Profit Recorded F12011 to FY2018 Rs. 21.61 billion
Profit after adjustment Rs. 14.62 billion
Excess Profit Rs.8.45 billion (Allowed Regulated Profit - Profit after
adjustment)
Amount withdrawn from Profits as Rs. 8.85 billion
Dividend
Equity Payback after CoD 2 - 3years
174
DETAILS OF SAVINGS IN FUEL COST
548. The fuel cost allowed as per tariff determination (provided by CPPA-G) exceeded
the fuel cost reported in the financial statements by an amount of Rs.3.36 billion,
which has ultimately contributed towards an excess profit of Rs.8.45 billion, as
presented below:
175
Contribution of Savings in O&M Expenses to Total Excess Profits
O&M Expenses allowed Rs.12.31 billion
O&M Expenses incurred Rs.8.42 billion
Difference in Allowed and Incurred O&M Rs.3.88 billion
Expenses
Details of Savings in O&M Expenses:
Net Delivered Total Variable As per Difference
Year Total Fixed O&M Total O&M Financials (Savings)
Energy O&M
Units in Billion Its, in Billion
1.562 1.040 0.328 1.368 0.771 0.598
FY 2010-11
1.063 0.767 0.339 1.106 0.648 0.458
FY 2011-12
1.276 1.023 0.401 1.424 0.811 0.613
FY 2012-13
1.464 1.257 0.473 1.730 1.478 0.252
FY 2013-14
1.410 1.229 0.484 1.712 1.027 0.685
FY 2014-15
1.272 1.145 0.498 1.643 0.942 0.701
FY 2015-16
1.240 1.147 0.494 1.641 1.627 0.014
FY 2016-17
1.171 1.146 0.535 1.681 1.118 0.562
FY 2017-18
10.458 8.754 3.552 12.306 8.423 3.883
Total FY 2011-2018
176
ADDITIONAL PROFITABILITY ON ACCOUNT OF SHORTFALL IN INVENTORY
SUMMARY OF FINDINGS
177
Uch-II Power Limited
Background
Date of October 8, 2008
Incorporation
Ownership Subsidiary of Engie Energy International
Structure
Size of Plant 404 MW
Location of Plant Dera Murad Jamali
CoD April 4, 2014
Term of PPA 25 Years
Details of Tariff
Tariff Petition Submitted on November 2008
Tariff Petition Admitted on December 2008
Tariff Petition Granted on April 2009
Tariff Control Period allowed 25 years
Project Cost allowed USD 471.132 million
ERR Allowed USD based equity - 15%
Breakdown EPC 366.764 million
of Project Other Costs 66.008 million
Cost allowed
(USD) Interest During Construction 38.360 million
Capital Tariff Determination COD Determination
14-04-2009 03-07-2017
Structure
and Project Equity 117.783 115.516
set-up cost Total debt 353.349 345.442
(USD Total Project Cost 471.132 460.958
million) Debt to Equity Ratio 75:25 74.94:25.06
Details of Tariff COD
EPC, total Project Costs Determination Determination
project cost 14-04-2009 03-07-2017
and changes EPC Cost 366.764 368.043
on account of Other costs 66.008 65.372
foreign Interest During Construction (IDC) 38.360 27.543
currency Total Project Cost 471.132 460.958
fluctuations Output of the plant 375.20MW 380.75MW
(USD
million)
550. To determine the profitability and dividend history of UCH-II, the financial
statements, documents provided by NEPRA, PPIB and CPPA-G and the relevant
publicly available information were reviewed for the period April 4, 2014 till June 30,
178
Review of Profitability and Dividends
04.04.2014 till 30.6.2018
Ca ital In'ected b S onsors
Rs. 11.20 billion
Allowed Re ulated Pro 't
Pro 't Recorded FY2014 to FY2018 Rs.9.79 billion @15% USD end ERR
Rs. 20.71 billion
Pro 't a er ad'ustment
Excess Profit Rs. 16.87 billion
Rs.7.08 billion
Allowed Regulated Profit - Profit after
ad'ustment)
Amount withdrawn from Profits as Rs. 6.59 billion
Dividend
End Pa back a er CoD
3 — 4 ears
Depreciation 20.713
Debt Service Cost (4.377) (3.870) (3.668) (3.220) (0.838)
(0.040) (0.007)
Donation (0.107)
Other Income (0.316) (0.307) (0.212)
Adjusted Profit as per FS (0.760)
16.865
(0.216)
179
DETAILS OF SAVINGS IN FUEL COST
The fuel cost allowed as per tariff determination (provided by CPPA-G) exceeded
the fuel cost reported in the financial statements by an amount of Rs.2.54 billion,
which has ultimately contributed towards an excess profit of Rs.7.08 billion, as
presented below:
180
Contribution of Savings in O&M Expenses to Total Excess Profits
O&M Expenses allowed
Rs.7.63 billion
O&M Expenses incurred
Rs.4.93 billion
in Allowed and Incurred O&M
Rs.2.70 billion
Details of Savings in O&M Expenses:
Net Delivered Total Variable
Energy O&M Total Fixed O&M Difference—
(Savings)
FY 2013-14
FY 2014-15
FY 2015-16
FY 2016-17
FY 2017-18
Total FY 2014-2018
181
SUMMARY OF FINDINGS
182
Atlas Power Limited
183
Review of Profitability and Dividends
18.12.2009 till 30.6,2018
Capital Injected by Sponsors Rs. 4.74 billion
Allowed Regulated Profit Rs.8.12 billion @15% USD equity IRR
Profit Recorded FY2011 to FY2018 Rs. 18.75 billion
Profit after adjustment Rs. 12.90 billion
Excess Profit Rs.4.78 billion (Allowed Regulated Profit - Profit after
adjustment)
Amount withdrawn from Profits as Rs. 12.68 billion
Dividend
Equity Payback after CoD 2 - 3 years
184
DETAILS OF SAVINGS IN FUEL COST
556. The fuel cost allowed as per tariff determination (provided by CPPA-G) exceeded
the fuel cost reported in the financial statements by an amount of Rs.1.50 billion,
Ti
which has ultimately contributed towards an excess profit of Rs.4.78 billion, as
presented below:
Contribution of Savings
in Fuel Cost to Total Excess Profits
Fuel Cost allowed
Rs. 118.50 billion
Fuel Cost incurred
Rs. 117.00 billion
Difference in Allowed and Incurred Fuel
Cost
Rs. 1.50 billion
Details of Fuel Savings
EPP (CPPA)
FS IPP Fuel Savings
Net Delivered Fuel
Year FCC Rate Energy FCC Amount Difference
Rs/kWh (Raw Material (Fuel allowed vs.
(Units in Consumed)
Billion) Consumed)
FY 2009-10 = C-D)
FY 2010-11 10.1499
15.062 14.987
FY 2011-12 14.0071
14.945 14.946
FY 2012-13 14.0984 (0.001)
19.498 19.175
FY 2013-14 14.3609
21.813 21.423
FY 2014-15 11.1051
FY 2015-16 15.856
6.5203
FY 2016-17 7.9280
10.599 10.510
FY 2017-18 9.4185
11,740 11.682
Total FY 2010-2018 10.9536 10.818 118.498 117.002
185
Contribution of Savings in O&M Expenses to Total Excess Profits
O&M Expenses allowed Rs.12.75 billion
O&M Expenses incurred Rs.11.05 billion
Difference in Allowed and Incurred O&M Rs.1.70 billion
Expenses
Details of Savings in O&M Expenses:
Net Delivered Total Variable As per Difference
Year Total Fixed O&M Total O&M Financials (Savings)
Energy O&M
Units in Billion Its, in Billion
FY 2009-10 0.891 0516 0.139 0.654 0.738 (0.084)
FY 2010-11 1.484 0.990 0366 1.356 1.003 0.353
FY 2011-12 1.067 0.768 0.332 1.101 1.179 (0.079)
FY 2012-13 1.383 1.093 0.418 1.511 1.552 (0.041)
FY 2013-14 1.519 1.303 0.492 1.795 1.735 0.061
FY 2014-15 1.462 1.274 0.510 1.784 1.721 0,063
FY 2015-16 1.230 1.109 0.524 1.633 1.037 0.597
FY 2016-17 1.337 1.237 0.542 1.779 1.306 0.473
FY 2017-18 1.246 1.220 0.571 1.790 1.520 0.270
Total FY 2010-2018 10.728 8.995 3.755 12.750 11.052 1.698
186
4
l
E
Shortfall in Inventory
Inventory Level Required by NEPRA
Average Quantity Maintained 30,024 tonnes
9,212 tonnes
' Benefit of Maintaining Lower Inventory Levels
Rs.0.97 billion
SUMMARY OF FINDINGS
tie Cr
Summary of Excess Earnings
Years in Fuel
Operation Since Cost O&M Un-identified Miscalculation Mismatch in deb Inventory
COD of IRR payments shortfall Total
8 1.50 Rs. in Billion
I 1.70 I 1.58 0.51 J 0.22 I 0.97 6.47
J
187
Engro Powergen Qadirpur Power Limited
Background
Ownership Subsidiary of Engro Energy Limited
Structure
Size of Plant 227 MW
Location of Plant Qadirpur Ghotki
CoD March 27, 2010
Term of PPA 25 Years
Details of Tariff
Tariff Petition Submitted on February 2007
Tariff Petition Granted on July 2007
Tariff Control Period allowed 25 years
Project Cost allowed USD 204.668 million
IRR Allowed USD based equity - 15%
Breakdown EPC 170.632 million
of Project Other Costs 19.053 million
Cost allowed
(USD) Interest During Construction 14.983 million
Capital Tariff Determination COD Determination
Structure 19-07-2007 01-04-2011
and Project Equity 56.11 55.33
set-up cost Total debt 168.32 136.721
(USD Total Project Cost 204.668 192.051
million) Debt to Equity Ratio 75:25 71.18:28.82
Details of Tariff COD
EPC, total Project Costs Determination Determination
project cost 19-07-2007 01-04-2011
and changes EPC Cost 170.632 160.335
on account of Other costs 19.053 22 70
foreign Interest During Construction (IDC) 14.983 9.016
currency Total Project Cost 204.668 192.051
fluctuations Output of the plant 216.80MW 217.298MW
(USD
million)
REVIEW OF PROFITABILITY AND DIVIDENDS
558. To determine the profitability and dividend history of EPQL, the financial statements,
documents provided by NEPRA, PPIB and CPPA-G and the relevant publicly
available information were reviewed for the period March 27, 2010 till June 30, 2018.
Details are as follows:
188
Review of Profitability and Dividends
27.03.2010 till 30.6.2018
Capital Injected by Sponsors Rs. 3.24 billion
Allowed Regulated Profit Rs.8.95 billion @1570 USD equity IRR
Profit Recorded FY2010 to FY2018 Rs. 17.09 billion
Profit after adjustment Rs. 11.98 billion
Excess Profit Rs.3.03 billion (Allowed Regulated Profit - Profit after
adjustment)
Amount withdrawn from Profits as Rs. 8.70 billion
Dividend
Equity Payback after CoD 2 -3 years
189
DETAILS OF SAVINGS IN FUEL COST
The fuel cost allowed as per tariff determination (provided by CPPA-G) exceeded
the fuel cost reported in the financial statements by an amount of Rs.2.32 billion,
which has ultimately contributed towards an excess profit of Rs.3.03 billion, as
presented below:
190
Contribution of Savings in O&M Expenses to Total Excess Profits
O&M Expenses allowed Rs.7.74 billion
O&M Expenses incurred
Rs.7.40 billion
Difference in Allowed and Incurred O&M
Expenses Rs.0.34 billion
Details of Savings in O&M Expenses:
Year Net Delivered Total Variable
Energy O&M Total Fixed O&M Total O&M As per Difference
Financials (Savings)
Units in Billion
Its. in Billion
FY 2009-10 1.200 0.190 0.221
FY 2010-11 0.911 0.352 0.060
1.665 0.428 0.360 0.787 0.522
FY 2011-12 1.767 0.266
0.481 0.372
FY 2012-13 0,852 0.574 0.278
1.334 0.396 0.326 0.722 0.982
FY 2013-14 1.722 (0.260)
0.539 0.445
FY 2014-15 0.984 0.847 0.138
1.424 0.454 0.451 0.905 1.065
FY 2015-16 1.339 (0.160)
0.442 0.471
FY 2016-17 0.913 1.060 (0.147)
1.737 0.588 0.490 1.078 0.952
FY 2017-18 1.526 0.126
0.582 0.502
Total FY 2010-2018 1.083 1.043 0.041
13.715 4.099
- 3.638 7.737 7.396 0.341
191
SUMMARY OF FINDINGS
192
Foundation Power Company (Daharki) Limited
Background
Ownership
Structure Subsidiary of Daharki Power Holdings Limited - British Virgin Island
Ultimate parent is Fauji Foundation Pakistan
Size of Plant 185 MW
Location of Plant Daharki Ghotki
CoD May 16, 2011
Term of PPA 25 Years
Details of Tariff
Tariff Petition Submitted on January 2006
Tariff Petition Granted on October 2006
Tariff Control Period allowed 25 years
Project Cost allowed USD 202.844 million
IRR Allowed USD based equity - 15%
Breakdown EPC
of Project 156.730 million
Other Costs
Cost allowed 21.459 million
(LISD) Interest During Construction
24.655 million
Capital Tariff Determination
Structure COD Determination
21-10-2006 28-11-2013
and Project Equity 50.711 53.017
set-up cost Total debt
(USD 152.133 159.051
Total Project Cost 202.844
million) 212.068
Debt to Equity Ratio 75:25
Details of 75:25
EPC, total Tariff COD
Project Costs Determination
project cost Determination
and changes EPC Cost 21-10-2006 28-11-2013
on account of Other costs 156.730 147.562
foreign 21.459 36.297
Interest During Construction (IDC) 24.655
currency Total Project Cost 28.209
fluctuations 202.844 212.068
Output of the plant 171.483MW
(LISD 180.097MW
million)
193
1
194
DETAILS OF SAVINGS IN O&M EXPENSES
564. O&M expenses allowed as per tariff determination (provided by CPPA-G)
exceeded the O&M expenses reported in the financial statements by an amount
of Rs.1.37 billion, which has ultimately contributed towards the excess profit of
Rs.1.77 billion. The working of comparison of O&M expense incurred and allowed is
as follows:
195
ADDITIONAL PROFITABILITY ON ACCOUNT OF MISMATCH IN DEBT
REPAYMENTS
..
Mismatch in Debt Repayments
NEPRA Allowed Debt Repayment Frequency Quarterly
Actual Debt Repayment Frequency (as per PPA) Monthly
Benefit because of Mismatch in Payment Frequency Rs.0.15 billion
SUMMARY OF FINDINGS
196
Sapphire Electric Company Limited
Background
Date of January 18, 2005
Incorporation
Ownership Subsidiary of Sapphire Fibres Limited
Structure
Size of Plant 225 MW
Location of Plant Muridke Sheikhupura
CoD October 5, 2010
Term of PPA 30 Years
Details of Tariff
Tariff Petition Submitted on February 2006
Tariff Petition Admitted on February 2006
Tariff Petition Granted on June 2006
Tariff Control Period allowed 30 years
Project Cost allowed USD 185.552 million
IRR Allowed
USD based equity - 15%
Breakdown EPC
of Project 190.01 million
Other Costs
Cost allowed 23.87 million
(USD) Interest During Construction
10.54 million
Capital Tariff Determination
Structure COD Determination
15-06-2006 21-09-2011
and Project Equity 54.922 58.907
set-up cost Total debt 130.629 154.060
(L/SD Total Project Cost 185.552 212.967
million) Debt to Equity Ratio 70.40:29.60 72.34:27.66
Details of
Tariff COD
EPC, total Project Costs
project cost Determination Determination
and changes 15-06-2006 21-09-2011
EPC Cost 143,90
on account of Other costs 158.85
foreign 66.162 69.285
Interest During Construction (IDC) 14.358
currency 25.715
Total Project Cost 185.552
fluctuations 212367
Output of the plant 209 MW
(L1SD 212.107MW
million)
197
Review of Profitability and Dividends
5.10.2010 till 30.6.2018
Capital Injected by Sponsors Rs. 4.24 billion
Allowed Regulated Profit Rs.8.08 billion @15% USD equity IRR
Profit Recorded FY2011 to FY2018 Rs. 12.54 billion
Profit after adjustment Rs. 9.43 billion
Excess Profit Rs.1.35 billion (Allowed Regulated Profit - Profit after
adjustment)
Amount withdrawn from Profits as Rs. 5.72 billion
Dividend
Equity Payback after CoD 5 -6 years
DETAILS OF EXCESS PROFIT OVER REGULATORY RETURN
566. A comparison of Adjusted Profits generated from operations with allowed
regulatory returns during the period July 1, 2011 to June 30, 2018 revealed that SECL
has earned an Excessive Profit of Rs.1.35 billion. Detailed working of the excess profit
is as follows:
198
DETAILS OF SAVINGS IN FUEL COST
567. The fuel cost allowed as per tariff determination (provided by CPPA-G) exceeded
the fuel cost reported in the financial statements by an amount of Rs.2.29 billion,
which has ultimately contributed towards an excess profit of Rs.1.35 billion, as
presented below:
199
ADDITIONAL PROFITABILITY ON ACCOUNT OF MISMATCH IN DEBT
REPAYMENTS
SUMMARY OF FINDINGS
200
Saif Power Limited
Background INIV
Date of
November 11, 2004
Incorporation
Ownership
Subsidiary of Saif Holdings Limited
Structure
Size of Plant 229 MW
Location of Plant Sahiwal
CoD April 30, 2010
Term of PPA 30 Years
Details of Tariff
Tariff Petition Submitted on
June 2006
Tariff Petition Granted on January 2009
Tariff Control Period allowed 30 years
Project Cost allowed
USD 213.173 million
IRR Allowed
USD based equity - 15%
Breakdown EPC
of Project Other Costs 157.062 million
Cost allowed 30.641 million
(USD) Interest During Construction
Capital 25.47 million
Structure Tariff Determination COD Determination
and Project 16-01-2009 20-06-2011
Equity
set-up cost 42.63 55.88
Total debt
(USD 170.54 181.07
Total Project Cost
million) 213.173 236.950
Debt to Equity Ratio
80:20 76:24
Details of
EPC, total Tariff COD
Project Costs
project cost Determination Determination
and changes EPC Cost 16-01-2009 20-06-2011
on account of Other costs 157.062 163.139
foreign Interest During Construction (JDC) 30.641 47.2
currency Total Project Cost 25.47 26.611
fluctuations Output of the plant 213.173 236.950
(USD 208.965MW 209.786M4V
201
Review of Profitability and Dividends
30.04.2010 till 31.12.2018
Capital Injected by Sponsors Rs. 3.86 billion
Allowed Regulated Profit Rs.9.22 billion @15% USD equity IRR
Profit Recorded F72011 to FY2018 Rs. 16.05 billion
Profit after adjustment Rs. 10.47 billion
Excess Profit Rs.1.26 billion (Allowed Regulated Profit - Profit after
adjustment)
Amount withdrawn from Profits as Rs. 7.61 billion
Dividend
Equity Payback after CoD 3 -4 years
202
DETAILS OF SAVINGS IN FUEL COST
570. The fuel cost allowed as per tariff determination (provided by CPPA-G) exceeded
the fuel cost reported in the financial statements by an amount of Rs.1.97 billion,
which has ultimately contributed towards an excess profit of Rs.1.26 billion, as
presented below:
203
ADDITIONAL PROFITABILITY ON ACCOUNT OF MISMATCH IN DEBT
REPAYMENTS
SUMMARY OF FINDINGS
204
Orient Power Company (Private) Limited
Background
Date of June 16, 2003
Incorporation
Ownership Subsidiary of Oman Oil Company
Structure
Size of Plant 229 MW
Location of Plant Balloki Kasur
CoD May 24, 2010
Term of PPA 30 Years
Details of Tariff
Tariff Petition Submitted on February 2005
Tariff Petition Granted on September 2009
Tariff Control Period allowed 30 years
Project Cost allowed USD 168.4 million
IRR Allowed
USD based equity - 15%
Breakdown EPC
of Project Other Costs 147.79 million
Cost allowed 20.666 million
(USD)
Capital
Tariff Determination COD Determination
Structure
and Project 17-09-2009 13-04-2011
Equity 42.57
set-up cost Total debt 61.165
(USD 125.83 134.601
Total Project Cost 168.4
million) Debt to Equity Ratio 195.766
75:25 69:31
Details of
EPC, total Tariff COD
Project Costs Determination
project cost Determination
and changes EPC Cost 17-09-2009 13-04-2011
on account of Other costs 147.79 147.79
foreign 20.666 47.976
Total Project Cost
currency 168.456 195.766
Output of the plant
fluctuations 225MW 212.70MW
(LISP
million)
205
Review of Profitability and Dividends
24.05.2010 till 30.6.2018
Capital Injected by Sponsors Rs. 4.45 billion
Allowed Regulated Profit Rs.7.87 billion @15% USD equity IRR
Profit Recorded FY2011 to PY2018 Rs. 9.85 billion
Profit after adjustment Rs. 8.93 billion
Excess Profit Rs.1.07 billion (Allowed Regulated Profit - Profit after
adjustment)
Amount withdrawn from Profits as Rs. 3.12 billion
Dividend
Equity Payback after CoD 5 - 6 years
206
DETAILS OF SAVINGS IN FUEL COST
573. The fuel cost allowed as per tariff determination (provided by CPPA-G) exceeded
the fuel cost reported in the financial statements by an amount of Rs.2.00 billion,
which has ultimately contributed towards an excess profit of Rs.1.07 billion, as
presented below:
207
ADDITIONAL PROFITABILITY ON ACCOUNT OF MISMATCH IN DEBT
REPAYMENTS
SUMMARY OF FINDINGS
208
Halmore Power Generation Company Limited
Background
Date of March 31, 2005
Incorporation
Size of Plant 225 MW
Location of Plant Bhilcld Sheikhupura
CoD June 15, 2011
Term of PPA 30 Years
Details of Tariff
Tariff Petition Submitted on July 2006
Tariff Petition Granted on September 2006
Tariff Control Period allowed 30 years
Project Cost allowed USD 184.382 million
IRR Allowed USD based equity - 15%
Breakdown EPC
of Project Other Costs 152.163 million
Cost allowed Interest during construction 49.258 million
(USD) 36.240
Capital Tariff Determination
Structure COD Determination
and Project 01-09-2006 08-01-2014
Equity 46.095
set-up cost Total debt 51.454
(USD 138.287 186.207
Total Project Cost 184.382
million) Debt to Equity Ratio 237.661
75:25 78.35:21.65
Details of
EPC, total Project Costs COD Determination
project cost EPC Cost 08-01-2014
and changes Other costs 152.163
on account of Interest during construction 49.258
foreign Total Project Cost 36.240
currency Output of the plant 237.661
fluctuations 212.70MW
(USD
million)
209
Review of Profitability and Dividends
15.06.2011 till 30.6.2018
Capital Injected by Sponsors Rs. 7.02 billion
Allowed Regulated Profit Rs.7.80 billion @15% USD equity IRR
Profit Recorded mon to F12018 Rs. 5.23 billion
Amount withdrawn from Profits as Rs. 0.86 billion
Dividend
SUMMARY OF FINDINGS
210
COAL BASED THERMAL PLANTS - POWER GENERATION POLICY
2015
BackgroUnd
Date of Incorporation May 28, 2014
Ownership Structure
Subsidiary of Huaneng Shandong Ruyi (HK) Energy Limited, which is 50%
owned by Huaneng Shandong Power Generation Company Limited and 50% by
Shandong Ruyi Science and Technology Group Company Limited.
Type of Plant Coal- fired
Size of Plant Gross Capacity: 1,320 MW
Net Capacity: 1,243.52 MW
Location of Plant Qadirabad, District Sahiwal
CoD October 28, 2017
TARIFF DETAILS
575. HSR requested an unconditional acceptance of NEPRA's upfront tariff for 2x660 MW
Coal Power Plant, which was approved by NEPRA 76
on March 31, 2015, with the
following cost assumption for the project:
1 -
F
76
NEPRA fiRF-308/HSRPEL-2015/4385-4387
T
211
•
576. As per the tariff documents, IDC will be re-established at the time of CoD based on:
Indexed capital cost (as per the formula given in the Upfront Coal Tariff 2014);
Actual premium on LIBOR & KIBOR subject to maximum of 4.5% and 3.5%,
respectively; and
578. HSR had requested an IDC of USD 197.33 million at CoD on the basis of the following
calculation:
212
liotwe to Proceed Date a 5
Neeonil Cumulaii
Debt "
Inietelt
Disburse Daum Nmiwuj Fauntial
Qui 4.cru 1
until mem LIBOR D 1-4 Total Cost of duringEbel'age Ra
Lie Etange
Debt Dan
Cusp Disbu °mouth In t",thr"""g
' Spread Debt Rate Conm,,,,,n
Date
on 11.50 (PER/u5D)
mIns (Ha 11:0
NInfr
1 1 310r 15 353,0 124 1 21 11 I 92 00 : 3!)01.1a 0 3086%1
2 111.'1.16 1.33% 121.1 i 4.309% 06 31-1u1-15 I 101.201
119.31 9100 30.0e4.15 0.3311% ,63 ,
30446 133% 121.1 4.30' 44.11% 2 30 114)er.11 I 103.201
1-2.3 294444
301u116 333% 121.1 0.6126% 1.50% 5.113% 3.r I
19143 91.00 29-Jaa.16 I 104.901 21466.00
1
29.491.16 0.136151 1304 013'41 64
1Oet.16 (43% 1211 620.31
5,A LI. 2991
571055 'mei
MOO 29,141.16 0.1911' 130V 5/59%
51995
110-144.11 SA% 124. '44.05 .53 3 101.601 '35.13
9100 28.0n46
-
1133% 121 169-6 9000 30)4/.1"
USW 1.301 to /semis _j_ taiii- Saul
14310% 1.30% 55:5331
66.'ci
124.1 9911- 91.00 28-Appl- 1,1-119
9 30-Ocur r4 33% 49.64 ism% 13:35 234.3'10344
1,04131 92.00 2111,1.1" ; 101 01 1,39'16
0.1146% I.;. A 55;161'1355: 15.11
10.jaa-18 Lanpray 22.1521- 105.30j 1494.10
10 4944
133% 1,09215 9240 LIMB limpeerulat 1
0.3006%
30410 Lareperailini
11% 15.133 Exebagt Rau 10431 1,656.75
11 3.13% 1941 1,11140 90.00 13011
latt2nmlint ,fr--- 1
579. Against HSR's request, NEPRA allowed US $ 167.912 million (Rs. 17,562.588 million) as
IDC at CoD. After incorporating the increased IDC as well as other adjustments
80,
the following project cost was allowed to HSR:
80
Including
instead a downward
of European revision of CAPEX on account of application of Capex adjustment formula and Chinese Boiler
Boiler
213
COMPARISON OF FINANCIAL STATEMENTS OF HSR WITH TARIFF
Note 13.1 of the financial statements of HSR for the year ended December 31, 2017
(COD year) reports an operational fixed asset carried at net book value of Rs. 172.19
billion, which translates into a cost of Rs. 173.25 billion after adding back relevant
accumulated depreciation of Rs. 1.06 billion.
The relevant extract of financial statements for the years 2015, 2016 and 2017 is
given below:
An in-depth review of the causes of excess allowance of Rs. 13.16 billion in setup
costs revealed:
214
For the year ended Dec 31, 2016:
Rs. 69,945,017,000 was borrowed during the year, details of which are tabulated
below:
Facility Draw down
Bank available Rate per annum In RS.
(USD) Repayment terms
million
ICBC-Beijing Branch 70 3m Libor + 1.15% 68 7,112.7
ICBC - Shandong branch I year from draw down
200 6m Libor + 0.6% 200
China Construction Bank 20,919.7 6 months from draw down
Corporation - Seoul 203.7 1.45% 203.7 21,306.7 6 months from draw down
Bank of China Limited 99 3m Libor + 0.8% 99 10,355.3
Industrial and 1 year from draw down
Commercial Bank of 100
China (Macau) 1.60% 98 10,250.7 For working capital 1 year
Total from draw down
668.7 69,945
Further, note 12.2.2.2 of the financial statements for the year ended Dec 31, 2016
revealed that the markup on these short terms loans for the year aggregated to
Rs. 482,861,000.
Rs. 155,929,000,000 was borrowed during the year from a consorfium of banks as
per the following details:
HSR achieved its CoD on October 28, 2017, and a review of note 13.2.2.2 of the
financial statements revealed that HSR incurred markup of:
Rs. 328,139,000 on the short-term loans obtained during the year ended Dec
31, 2016: and
215
584. A comparison of the markup amounts reported in the financial statements with
those allowed by NEPRA in CoD tariff adjustments revealed that IDC overpayment
has contributed to 80% of the total overpayment amount of Rs. 13.17 billion
overpaid on account of setup cost. Details are as follows:
NOTE: The remaining amount of Rs. 2.3 billion is to be further investigated since the
requisite information was not available at the time of submission of this report.
HSR claimed IDC based on markup on long term loan @ LIBOR + 4.5% during the
entire construction period, whereas, the financial statements of the Company
revealed that the Company did not borrow any funds during the first year of
construction and obtained short term loans at substantially lower interest rates
during the second year of construction. Apparently therefore, there is an element
of misrepresentation by the sponsors of the IPP.
HSR didn't share complete information with NEPRA for adjustment of the IDC
component of project cost. During the construction period, the spread over LIBOR
actually ranged from 0.6% to 1.6%, whereas the Company claimed interest during
construction at LIBOR + 4.5% flat spread.
Para 56 xii (b)(D) of the Upfront Tariff 2014 mandates that any reduction in spread is
to be shared between the Power Purchaser and Power Producer in a ratio of 60:40.
Such reduction would have decreased the IDC resulting in reduction of tariff at
COD.
589. Based on this adjusted equity amount, HSR was entitled to a return of USD 70.90
million per year. However, HSR has been allowed USD 98.30 million, resulting in an
excess of USD 27.40 million in annual return payments as elaborated in the table
below:
590. Given the reference exchange rate of RS. 155 per USD, and assuming that USD
appreciates against PKR at an average rate of 6% per annum (actual yearly
depreciation was around 6.87% during last 9 years), the excess payment works out
to be RS. 291.04 billion
over the tariff control period of 30 years.
217
Port Qasim Electric Power Company (Private) Limited(PQE)
, ,
Background
Date of Incorporation August 12, 2014
Ownership Structure Wholly-owned subsidiary of Port Qasim Energy Dubai (Holding) Limited, which
is 51% held by Port Qasim Energy (Hong Kong) Holding Limited and 49% by AI-
Mirqab Capital S.P.C. Qatar holds 49% of the shares.
Type of Plant Coal-fire pure condensation power units
Size of Plant 2 x 660 MW
Location of Plant Port Qasim, Karachi
CoD April 25, 2018
TARIFF APPROVAL
PQE requested an unconditional acceptance of NEPRA's upfront tariff for 2 x 660
MW Coal Power Plant, which was approved by NEPRA8I on February 13, 2015, with
the following cost assumption for the project:
As per the tariff document, IDC was to be re-established at the time of CoD based
on:
81 NEPRA/TRF-299/PQEPCPL-2015/1839-1841
218
Withholding tax on contracts/services;
actual premium on LIBOR & KIBOR subject to maximum of 4.5% and 3.5%
respectively; and
593. Capital cost was also to be adjusted as per the formula given in the Upfront Coal
Tariff 2014.
PQE had requested an IDC of USD 221.907 million at CoD on the basis of the
following calculation:
597. After incorporation of increased IDC as well as other adjustments, the following
project cost was allowed to the Company:
The relevant extract of financial statements for the years 2015, 2016, 2017 and 2018
is given below:
220
As at 30.6.2015 30.6.2016 31.12.2016 31.12.2017 31.12.2018
Pro en Plant and E UI nent Rupees
711 000 136,937,000
Ca dal Work in Profess 125,363,000 94,109,000
702,788,000 44,942,214,000 235,069,896,000
Advances to suppliers 116,231,729,000 177,682,051,000
11,876,000 16,851,148,000 5,492,023,000
Capital spares 3,331,612,000 3,350,517,000
715,375,000 5,587,659,000
Cash and bank balance 61,930,299,000 121,849,115,000 181,107,772,000 244,008,072,000
126,774,000 6,915,079,000 11 ,309,980,000
Financed by: 3,031,154,000 23,724,855,000
Share capital 497,074,000
Borrowing 23,022,281,000 31,969,155,000 48,420,880,000 73,723,000,000
Total 43,974,000,000 93,796,000,000 129,616,500,000 216,300,500,000
497,074,000 66,996,281,000 125,765,155,000 1
78,037,380,000 290,023,500,000
600. It is pertinent to note:
601. An in-depth review of the causes of excess allowance of USD 182.532 million in setup
costs revealed
Only equity aggregating to Rs. 497.074 million was injected to finance the project
and there was no borrowing. Therefore, there was no interest cost during this time
period.
Long term borrowing of USD 1,555,000,000 was negotiated with The Export-
Import Bank of China @6 months LIBOR plus 3.7%; and
221
Note 3.2 of the financial statements showed the markup on this borrowing for the
year ended June 30 2016 aggregated to USD 29,220,000 (Rs. 3,053,490,000).
Further, as per CoD determination, PQE was allowed an equity of Rs. 45.19 billion,
against which PQE had already injected equity of Rs. 73.72 billion leading to an
excess equity of Rs. 28.53 billion which was in fact not required for the project
and is mainly reflected in cash and bank balance of Rs. 23.72 billion at the year
end.
602. A comparison of the markup amounts reported in the financial statements with
those allowed by NEPRA in CoD tariff adjustments revealed that the financing cost
overpayment has contributed to two-third of the total amount of USD 182.532 million
(Rs19.3 billion) overpaid on account of setup cost. Details are as follows:
222
USD RS.
Financing Cost sought by PQE
Financing Cost allowed by NEPRA
234.913 million 24.84 billion
Financing Cost reported in Financial Statements
I 112.788 million
12.53 billion
Excess Financing Cost allowed (Allowed - Reported)
122.125 million 12.31 billion
NOTE: The remaining one third excess financing cost is to be further investigated
since the requisite information was not available at the time of submission of this
report.
603. Unlike in the case of HSR, in the case of PQE, NEPRA corrected the error of the
construction period and assumed actual construction period to compute return
during the construction period.
P
I
223
n.
RENEWABLE POWER PLANTS - 2006 AND 2013 POLICIES ,
Background
Formerly Green Power (Pvt.) I .imIted (C FL)
Ownership Structure Fauji Fertilizer
Size of Plant 50 MW
Location of Plant Gharo, District Thatta, Sindh Province
CoD December 10, 2014 .
Details of Tariff
Original Tariff for GPL granted on April 27, 2007
Tariff. Petition Re-Submitted on September 9, 2011
Tariff Petition Admitted on September 14, 2011
Tariff Granted to FWEL-II on March 16, 2012
Tariff Control Period sought 20 years
EPC Project Turney basis — no detail of equipment provided
Project Cost allowed USD 124.907 million
IRR Allowed 17% for a period of 20 years
Debt Repayment Period allowed 10 years with repayment schedule on a Biannual basis
Tariff Adjustment after CoD Allowed June 9, 2016
on
Capital Determination COD Determination
Structure 16-03-2012 09-06-2016
and Project Equity 3/.227 34.580
set-up cost Total debt 93.680 88.919
(USD Total Project Cost 124.907 123.499
million) Debt to Equity Ratio 75:25 72:28
Details of Tariff COD
EPC, total Project Costs Determination Determination
project cost 16-03-2012 09-06-2016
(USD EPC Cost 111.023 108.663
million) and Non-EPC costs 1.000 0.820
changes on Project development costs 2.750 2.929
account of Duties and taxes 0.716 0.740
foreign Pre-COD insurance 1.499 1.029
currency Financial charges 2.632 2.466
fluctuations Interest during construction 5.287 6.849
Total Project Cost 124.907 123.497
224
publicly available information were reviewed for the period starting from CoD till
June 30, 2019. Details are as follows:
225
ADDITIONAL PROFITABILITY ON ACCOUNT OF INCORRECT IRR
CALCULATION
226
Sapphire Wind Power Company Limited (SWPCL)
Background
Ownership Str,. wlure
Sae of Plan Sapphire Group
49.50 MW
Upgrade the Size of Plant on Nor' 9, 2014
Location of Plant 52.80 MW
himpir, District Thatta, Sindh Province
Details of Tariff
Original Tariff for SWPCL granted on
Tariff Petition Submitted on April 27, 2007
— Tariff Petition Admitted on September 12,2011
Tariff (Cost plus) Granted to SWPCL on September 14, 2011
Tariff (Upfront) Granted to SWPCL on
May 8, 2012
Tariff Control Period sought November 21, 2013
EPC Project 20 years
Project Cost allowed Tumey basis — no detail of equipment provided
1RR Allowed USD 128.872 million
Debt RepaymentPeriod allowed 17% for a period of 20 years
10 years with repayment schedule on a Biannual basis
Capital
Determination - 08-05-2012
Structure and
Project set-up Equity
cost (USD Total debt 32.218
million) Total Project Cost 96.654
Debt to Equity Ratio 128 872
Details of EPC, 75:25
total project Project Costs
EPC Cost Tariff Determination 08-05-2012
cost (USD 107,500
million) and Letter of credit confirmation charges
Non-EPC costs 1.095
changes on 1.348
account of Project development costs
Land cost 2.891
foreign
Duties and taxes 0i19
currency
Pre-COD insurance 0.719
fluctuations
Financial charges 1.466
Sirtosure fee 3.602
Working capital 4.635
Interest during construction 0.992
Total Project Cost 4.505
128.872
227
Review of Profitability and Dividends
1.7.2015 till 30.6.2019
Capital Injected by Sponsors Rs.3.26 billion
Allowed Regulated Profit Rs.2.68 billion
Profit Recorded FY 2016 to FY 2019 Rs.3.74 billion
Profit after adjustment Rs.2.74 billion
Excess Profit Rs.0.056 billion (Allowed Regulated Profit - Profit after
adjustment)
Amount withdrawn from Profits as Rs.0.73 billion
Dividend
228
41.1..Xt
229
Zoriu Enerji Pakistan Limited (ZEPL)
Background
Size of Plant 49.50 MW
Upgrade the Size of Plant on May 2008 50 MW
Upgrade the Size of Plant on July 2011 56.40 MW
Location of Plant Jhimpir, near Nooriabad, District Thatta, Sindh Province
CoD July 26, 2013
Details of Tariff
Original Tariff for ZEPL granted on December 18, 2007
Tariff Petition Re-Submitted on May 23, 2008
Tariff Petition Re-Submitted on July 19, 2011
Tariff Petition Admitted on September 14, 2011
Tariff Granted to ZEPL on December 18,2007 & July 19, 2011
Tariff Control Period sought 20 years
EPC Project Tumey basis — no detail of equipment provided
Project Cost allowed USD 108.942 million
IRR Allowed 17% for a period of 20 years
Debt Repayment Period allowed 10 years with repayment schedule on a Quarterly basis
Tariff Adjustment after CoD Allowed on February 20, 2015
Capital Determination COD Determination
Structure 18-12-2007 20-02-2015
and Project Equity 21.788 39.103
set-up cost Total debt 87.154 91.239
(USD Total Project Cost 108.942 130.342
million) Debt to Equity Ratio 80:20 70:30
Details of Tariff COD
EPC, total Project Costs Determination Determination
project cost 18-12-2007 20-02-2015
(USD EPC Cost /02.212 117.394
million) and Non-EPC costs 1.692 4.588
changes on Project development costs 0.081 -
account of Duties and taxes 0.415 0.973
foreign Pre-COD insurance 0.965 2.582
currency. Financial charges 3.577 4.805
fluctuatio
ns Total Project Cost 108.942 130.342
230
Review of Profitability and Dividends
1.1.2013 till 31.12.2018
Casual In'ected b S onsors
Rs.2.921 billion
Allowed Re ulated Pro 't
Rs.4.62 billion
Pro it Recorded FY 2013 to FY 2018
Pro t a ter ad'ustment Rs.3.47 billion
Excess Profit Rs.3.43 billion
Rs.0.00 billion
Allowed Regulated Profit - Profit after
ad'ustment)
Amount withdrawn from Profits as
Dividend Rs.0.00 bil ion
-
ADDITIONAL PROFITABILITY ON ACCOUNT OF INCORRECT IRR
CALCULATION
231
Three Gorges First Wind Farm Pakistan (Pvt.) Limited
Background
Size of Plant 49.50 MW
Location of Plant Jhimpir, near Nooriabad, District Thatta, Sindh Province
CoD November 25, 2014
Details of Tariff
Original Tariff for Three Gorges-I granted December 15, 2011
on
Tariff Petition Submitted on June 9, 2011
Tariff Petition Admitted on June 24, 2011
Tariff (Cost Plus) Granted to Three Gorges- December 15,2011
I on
Tariff Control Period sought 20 years
EPC Project Turney basis — no detail of equipment provided
Project Cost allowed USD 130.279 million
IRR Allowed 17% for a period of 20 years
Debt Repayment Period allowed 10 years with repayment schedule on a Biannual basis
Tariff Adjustment after CoD Allowed on January 22, 2016 & October 28, 2016
Capital Determination COD Determination
Structure 15-12-2011 28-10-2016
and Project Equity 26.056 25.823
set-up cost Total debt 104.223 103.292
(USD Total Project Cost /30.279 129.115
million) Debt to Equity Ratio 80:20 80:20
Details of Tariff COD
EPC, total Project Costs Determination Determination
project cost 15-12-2011 28-10-2016
(USD EPC Cost 110.315 109.998
million) and Non-EPC costs 1.10 1.10
changes on Project development costs 2.93 2.93
account of Duties and taxes 0.419 1.019
foreign Pre-COD insurance 1.489 0.800
currency Financial charges 2.79 2.780
fluctuations Sinosure fee 6.806 6.745
Interest during construction 4.43 3.742
Total Project Cost 130.279 129.114
232
Review of Profitability and Dividends
1.1.2014 till 31.12.2018
Ca z al I S lanai Rs 2.555 billion
Allowed Re ula ed Pro
Pro Recorded FY 2014 to FY 2018 Rs.2.48 billion
Pro '1. a ter ad 'ustment Rs.3.59 billion
Excess Profi Rs.2.49 billion
Rs.0.014 billion Allowed Regulated Profit - Profit after
ad'ustment)
Amount withdrawn from Profits as
Dividend Rs.0.00 billion
233
fl
'
ADDITIONAL PROFITABILITY ON ACCOUNT OF INCORRECT IRR
CALCULATION
234
FFC Energy Limited (FFCEL)
NeWnW,WittiVP0.44#0,01!$ Background
Ownership Structure
Size of Plant Fauji Fertilizer Company Limited
Location of Plant 49.50 MW
CoD Jhimpir, District Thatta, Sindh Province
May 16, 2013
Details of Tariff
Original Tariff for FFCEL granted on
Tariff Petition Submitted on August 10, 2010
Tariff Petition Admitted on
April 7, 2010
Tariff (Cost Plus) Granted to FFCEL on April 15, 2010
:-"- August 10, 2010
Tariff Control Period sought
EPC Project 20 years
Project Cost allowed Turney basis — no detail of equipment provided
IRR Allowed USD 133.557 million
Debt Repayment Period allowed 17% for a period of 20 years
Tariff Adjustment after CoD Allowed on 10 years with repayment schedule on a Biannual basis
November 10, 2014
Capital
Structure Determination COD Determination
and Project 10-08-2010 10-11-2014
Equity 26.711
set-up cost Total debt 26.700
(1.15D 106.846 106,802
Total Project Cost /33.557
million) Debt to Equity Ratio 133.501
Details of 80:20 80:20
EPC, total Tariff COD
Project Costs Determination
project cost Determination
(LISD EPC Cost 10-08-2010 10-11-2014
million) and LC Opening Charges 111.199 111.199
changes on Duty and taxed
1.250 0.355
account of Non-EPC Cost 0.693 0.558
foreign
currency Project development costs 3.873 3.556
fluctuations Pre-COD Insurance
Financial Charges 1.518 1.350
Interest During Construction 3.102 2.808
Total Project Cost 11.922 13.675
133.557 133.501
235
Review of Profitability and Dividends
1.1.2013 till 31.12.2018
Capital Injected by Sponsors Rs.2.438 billion
Allowed Regulated Profit Rs.3.42 billion
Profit Recorded FY 2013 to FY 2018 Rs.4.21 billion
Profit after adjustment Rs.2.85 billion
Excess Profit Rs.0.00 billion (Allowed Regulated Profit - Profit after
adjustment)
Amount withdrawn from Profits as Rs.0.80 billion
Dividend
236
Foundation Wind Energy-I LIMITED (FWEL-I)
Back ound
Ownershz Structure
Size o Plant Fauj Foundation
Location o Plant 50 MW
CoD G a o, District T atta, Sind Province
A ril 11,2015
Details o Tan
On: inal Tar,; or FEWL I anted on
Tan 5 Petition Submitted on March 16, 2012
Ta ij Petition Admitted on Se • tember 9, 2011
Tan i (Cost Plus) Granted to FEWL-I on Se tember 14, 2011
Mar 16, 2012
Tan; Control Period sour ht
EPC Pro ect 20 ears
Tu ne basis - no detail of e u ment ov ded
Pro ect Cost allowed
7 IRR Allowed USD 128.703 million
17 for a e iod of 20 ears
Debt Re a ment Period allowed
10 ears wit re a
Tan; Ad ustment a ten CoD Allowed on ment s edule on a Biannual basis
October 27, 2016
Capital
Structure Determination COD Determination
and Project E • ui 08-05-2012 27-10-2016
set-up cost 32.176
Total debt 30.114
(USD 96.527
Total Pro'ect Cost 95.360
million) 128.702 125.473
Debt to E ui Ratio
Details of 75:25 74:26
EPC, total Tariff COD
Project Costs
project cost Determination Determination
(USD EPC Cost 08-05-2012 27-10-2016
million) and Nlon-EPCcosts 111.939 1 0.272
changes on
Proectdevelo 'merit costs
account of Land cost
3.750
foreign
Duties and taxes
currency
Pre COL) insurance 0.689
fluctuations
FularKialchar es 1.039
VVorkin casital 2.604
Interestatrin Construction
Total Pro ect Cost 7.119
128.702 C 1,2
237
Review of Profitability and Dividends
1.7.2015 till 30.6.2019
Capital Injected by Sponsors Rs.3.502 billion
Allowed Regulated Profit Rs.2.93 billion
Profit Recorded FY 2015 to FY 2019 Rs.4.05 billion
Profit after adjustment Rs.3.07 billion
Excess Profit Rs.0.145 billion (Allowed Regulated Profit - Profit after
adjustment)
Amount withdrawn from Profits as Rs.0.15 billion
Dividend
Finance Cost Short Term 0.004 0.029 0.051 0.098 0.012 0.194
Allowed Regulatory
Return 0.922 0.465 0.535 0.768 0.237 2.927
238
ADDITIONAL PROFITABILITY ON ACCOUNT OF INCORRECT IRR
CALCULATION
In
239
Hydro China Dawood Power (Pvt.) Limited (DPPL)
Background
Formerly Dawood Power (Pvt.) Limited (formerly Win Power
(Pvt.) Limited (WPL)
Size of Plant 50 MW
Location of Plant Gharo, District Thatta, Sindh Province
Details of Tariff
Original Tariff for DPPL granted on December 6, 2008
Tariff Petition Submitted on July 16, 2008
Tariff Petition re-Submitted on May 2013
Tariff (Cost Plus) Granted to DPPL on December 6, 2008
Tariff (Upfront) Granted to DPPL on April 23, 2014
Tariff Control Period sought 20 years
EPC Project Turney basis — no detail of equipment provided
Project Cost allowed USD 133.140 million
IRR Allowed 17% for a period of 20 years
Debt Repayment Period allowed 10 years with repayment schedule on a Biannual basis
Tariff Adjustment after CoD Allowed on October 27, 2016
Capital Tariff Determination
Structure 06-12-2008
and Project Equity 26.628
set-up cost Total debt 106.512
(USD Total Project Cost 133.140
million) Debt to Equity Ratio 80:20
Details of Tariff Determination
Project Costs 06-12-2008
EPC, total
project cost EPC Cost 119.933
(USD Project development and
million) and management 3.739
changes on Fee and other non-EPC costs 1.210
account of Financing fee/charges 4.656
foreign Interest During Construction 3.602
currency
fluctuations Total Project Cost 133.140
24 1
Quaid-E-Azam Solar Power (Privatel Limited (QASPL)
Background
Ownership Structure Owned by the Government of Pakistan
Size of Plant 100 MW
Location of Plant LalSohanra in Cholistan, District Bahawalpur, Punjab
Province
CoD July 15, 2015
Details of Tariff
Original Tarifffor QASPL granted on January 22, 2015 & June 2, 2016
Tariff Petition Submitted on
Tariff (Upfront) Petition re-Submitted on February 25, 2015
Tariff Petition Admitted on February 27, 2015
Tariff (Cost plus) Granted to QASPL on January 22,2015
Tariff (Upfront) Granted to QASPL on June 2, 2016
Tariff Control Period sought 25 years
EPC Project Tumey basis — no detail of equipment provided
Project Cost allowed USD 124.907 million
IRR Allowed 17% for a period of 25 years
Debt Repayment Period allowed 10 years with repayment schedule on a Quarterly basis
Tariff Adjustment after CoD Allowed on June 2, 2016
Capital Determination COD Determination
Structure 22-01-2015 02-06-2016
and Project Equity 37.858 37.655
set-up cost Total debt 113.573 112.964
(USD Total Project Cost 151.431 150.619
million) Debt to Equity Ratio 75:25 75:25
Details of Tariff COD
EPC, total Project Costs Determination Determination
project cost 22-01-2015 02-06-2016
(USD EPC Cost 131.150 131.150
million) and Duties and taxes 4.737 2.457
changes on Non-EPC cost 4.350 4.351
account of Project development cost 3.666 3.665
foreign Insurance during construction 1.019 1.019
currency Financing fee and charges 3.804 3.804
fluctuations Interest during construction 2.705 4.172
Total Project Cost 151.431 150.618
242
publicly available informatibh were reviewed for the period starting from CoD till
June 30, 2019. Details are as follows:
E 243
Apollo Solar Development Pakistan Limited LASDPL)
Background
Size of Plant 100 MW
Location of Plant LalSohanra in Cholistan, District Bahawalpur, Punjab
Province
CoD May 31, 2016
Details of Tariff
Original Tariff for ASDPL granted on January 22, 2015
Tariff Petition Submitted on
Tariff (Upfront) Petition re-Submitted on Marcy 20, 2015
Tariff (Cost plus) Granted to ASDPL on January 22,2015
Tariff (Upfront) Granted to ASDPL on May 26, 2015
Tariff Control Period sought 25 years
EPC Project Turney basis — no detail of equipment provided
Project Cost allowed USD 151.431 million
IRR Allowed 17% for a period of 25 years
Debt Repayment Period allowed 10 years with repayment schedule on a Quarterly basis
Tariff Adjustment after CoD Allowed on November 16, 2017
Capital Determination COD Determination
Structure 26-05-2015 16-11-2017
and Project Equity 37.858 31.322
set-up cost Total debt 113.573 117.832
(USD Total Project Cost 151.431 149.152
million) Debt to Equity Ratio 75:25 79:21
Details of Tariff COD
EPC, total Project Costs Determination Determination
project cost 26-05-2015 16-11-2017
(USD EPC Cost 131.150 131.150
million) and Duties and taxes 4.737 2.160
changes on Non-EPC cost 4.350 4.350
account of Project development cost 3.666 3.665
foreign Insurance during construction 1.019 1.019
currency Financing fee and charges 3.804 3.804
fluctuations Interest during construction 2.705 2.280
Sinosure Fee 0.724
Total Project Cost 151.431 149.152
244
Review of Profitability and Dividends
1.1.2016 till 31.12.2018
Ca ital In'ected b S onsors
Allowed Re ulated Pro I Rs.3.45 billion
Pro 't Recorded FY 2016 to FY 2018 Rs.1.81 billion
Pro *t a ter atustment Rs.2.58 billion
Excess Profit Rs.1.52 billion
Rs.0.00 bil ion
ad'ustment) Allowed Regulated Profit - Profit after
Amount zvithdrawn from Profits as
Dividend Rs.0.66 billion
245
Best Green Energy Pakistan Limited (BGEPL)
Background
Size of Plant 100 MW
Location of Plant LalSohanra in Cholistan, District Bahawalpur, Punjab
Province
CoD May 31, 2016
Details of Tariff
Original Tariff for BGEPL granted on January 22, 2015
Tariff Petition Submitted on
Tariff (Upfront) Petition re-Submitted on Marcy 3,2015
Tariff (Cost plus) Granted to BGEPL on January 22,2015
Tariff (Upfront) Granted to BGEPL on May 26, 2015
Tariff Control Period sought 25 years
EPC Project Turney basis — no detail of equipment provided
Project Cost allowed USD 151.431 million
IRR Allowed 17% for a period of 25 years
Debt Repayment Period allowed 10 years with repayment schedule on a Quarterly basis
Tariff Adjustment after CoD Allowed on -
Capital Determination COD Determination
Structure 26-05-2015 16-11-2017
and Project Equity 37.858 31.322
set-up cost Total debt 113.573 117.832
(USD Total Project Cost 151.431 149.152
million) Debt to Equity Ratio 75:25 79:21
Details of Tariff COD
EPC, total Project Costs Determination Determination
project cost 26-05-2015 16-11-2017
(USD EPC Cost 131.150 131.150
million) and Duties and taxes 4.737 2.160
changes on Non-EPC cost 4.350 4.350
account of Project development cost 3.666 3.665
foreign Insurance during construction 1.019 1.019
currency Financing fee and charges 3.804 3.804
fluctuations Interest during construction 2.705 2.280
Sinosure Fee - 0.724
Total Project Cost 151.431 149.152
246
Review of Profitability and Dividends
1.1.2016 till 31.12.2018
Capital In'ected b S onsors
Allowed Re ulated Pro 't Rs.3.23 billion
Pro t Recorde FY 2016 to FY 2018 Rs.1.56 billion
Pro ía er adYstment Rs.1.38 billion
Excess Profit Rs.1.41 billion
Rs.0.00 billion
ad'ustment) Allowed Regulated Profit - Profit after
Amount withdrawn from Profits as
Dividend Rs.0.19 billion
247
Crest Energy Pakistan Limited (CEPL)
Background
Size of Plant 100 MW
Location of Plant LalSohanra in Cholistan, District Bahawalpur, Punjab
Province
CoD May 31, 2016
Details of Tariff
Original Tariff for BGEPL granted on January 22, 2015
Tariff Petition Submitted on
Tariff (Upfront) Petition re-Submitted on Marcy 20, 2015
Tariff (Cost plus) Granted to BGEPL on January 22, 2015
Tariff (Upfront) Granted to BGEPL on May 26, 2015
Tariff Control Period sought 25 years
EPC Project Tumey basis — no detail of equipment provided
Project Cost allowed USD 151.431 million
IRR Allowed 17% for a period of 25 years
Debt Repayment Period allowed 10 years with repayment schedule on a Quarterly basis
Tariff Adjustment after CoD Allowed on
Capital Determination COD Determination
Structure 26-05-2015 16-11-2017
and Project Equity 37.858 36.781
set-up cost Total debt 113.573 112.676
(USD Total Project Cost 151.431 149.457
million) Debt to Equity Ratio 75:25 75.39:24.61
Details of Tariff COD
EPC, total Project Costs Determination Determination
project cost 26-05-2015 16-11-2017
(USD EPC Cost 131.150 131.150
million) and Duties and taxes 4.737 2.234
changes on Non-EPC cost 4.350 4.350
account of Project development cost 3.666 3.665
foreign Insurance during construction 1.019 1.019
currency Financing fee and charges 3.804 3.804
fluctuations Interest during construction 2.705 2.551
Sinosure Fee 0.684
Total Project Cost 151.431 149.457
248
Review of Profitability and Dividends
1.1.2016 till 31.12.2018
Ca ital In'ected b S onsors
Allowed Re ulated Pro t Rs.3.83 billion
Rs.1.94 billion
Pro 't Recorded FY 2016 to FY 2018
Pro t a ter a 'ustment Rs.1.89 billion
Excess Profit Rs.1.89 billion
Rs.0.00 billion (Allowed Regulated Profit - Profit after
actustment)
Amount withdrawn from Profits as
Dividend Rs.0.46 billion
249
2013 FRAMEWORK FOR POWER CO-GENERATION IPP-WISE
JDW Sugar Mills Limited Bagasse Power Plants at JDW Sugar Mills Unit-
11(26.35 MW) and Unit-III (26.35 MW) (JDW)
Background
Date of Incorporation • On May 31, 1990 as private limited company
• Converted to public limited company on August 24, 1991
• Listed on Pakistan Stock Exchange
Type of Plant Bagasse based Co-Generation
EPA with CPPA-G since March 20, 2014
Location of Plant • JDW Unit-II, Sadiqabad, Rahim Yar Khan, Punjab
• JDW Unit-III, Ghotld, Sindh
CoD Unit II on June 12, 2014
Unit III on October 3, 2014
The main business activity of JDW Sugar Mills Limited is production of sugar, therefore
the required information pertaining to power generation was not available in its
financial statements. However, the collective Adjusted Profit pertaining to projects
JDW-Il and JDW-III were calculated using information reported in the Group
Reportable Segment under the head "Co-Generation segment" in the
consolidated financial statements of JDW Sugar Mills Limited.
The adjusted profit was compared with the allowed RoE to identify an excess profit
of Rs. 3.85 billion made by the two projects JDW-II and JDW-II, details of which are
tabulated below:
250
Profit before fax 123,517,157 1,244,322,076 1,510,511,811 2,039,658,102 1,910,423,319
1,250,229,327 8,078,661,792
Add: Depreciation 47,518405
Add: 346,216,614 331,8135,870 312,948,859 293,496,250 274,450,973 1,606,517,171
Finance cost 75,836,298 520,369,425 387,551,148 336,255,441
Less: Debt service JDW 11 398,204,643 974,686,861 2,692,903,814
226,752,791 596,096490 526,642,114 569,131,900 588,449,013 789,647,845 3,294720,353
Less: Debt service JDW 111
621,671,204 510,171,883 550,660,245
Less: 629,325,162 624,715,939 2,936,544,933
Working Cap JDW II 10,083,720 25,893,413 20,487,627 21,60.3,104 21507,869
Less: Working Cap JDW 111 37,023,534 137,599,266
27,108,067 19,855,790 20,899,111 24,057,347 28,765,502 120,685,818
Adjusted profit 10,035,549 840,138,741 1,152,791,413 1
,524,568,042 1,337,789,821 1,019,214,341 5,886,532,907
ROE allowed JDW II 60,199,753 165,171,414 174,197,030 188,806,339 204,378431 279,600,718 1,072,353,886
ROE allowed JDW 171,091,323 168,697,120 188,157,283
Total ROE 218,280,017 218,120,717 964,346,460
60,199,753 336,262,737 342,894,150 376,963,622
422,658448 497,721,435 2,036,700,346
Excess return (50,164,204) 503,876,004 809,897,262 1,149,604,420 915,126,173
521,492,906 3.849,832.561
In order to determine the reasons for excess profit, the reasonableness of the tariff
determination of JDW was reviewed. The assumption of a plant factor of 45% as
used in the tariff determination was corroborated with the actual plant utilization
(annual Net Electrical Output) leading to the following findings:
r.
ACTUAL ENERGY GENERATION — EXCESSIVE GAINS OF RS. 4 BILLION
JDW-II and JDW-III were producing electricity in excess of the 45% presumed plant
factor in the tariff determination. The recovery of fixed cost and debt service cost
has already been accounted for in this, meaning that any electricity production in
excess of 45% would result in excess recovery of fixed cost and debt service cost.
The actual recovery of such cost is linked with actual energy production rather than
plant factor determined at 45%. Detail of the excess gains earned by the two
projects aggregating to Rs. 3,959,697,911
on this account is tabulated below:
FT
251
Output at 45% Payment on account of
Net Electrical Payment on account of fixed (PPA contract capacity) fixed components 0 Excessive pins
Year Output components (24.37MW x 45% x 365 x 24) 45%
252
RYK Mills Limited Bagasse Power Plant (30 MW)
Type of Plant
Bagasse fired electric power generation facility
EPA with CPPA-G since October 10, 2014
Location of Plant
Ralcanabad, Rahfin Yar Khan, Punjab
CoD
March 23,2015
The actual recovery of such cost is linked with actual energy production rather than
plant factor determined at 45% by NEPRA. Detail of the excess gains earned by the
project aggregating to Rs. 1,002,008,288 on this account is tabulated below:
253
Net Electrical Payment on account Output at 45% (PPA contract capacity) Payment on account of Excessive gains
Year Output of fixed components (20.73M1N x 45% x 365 x 24) fixed components@ 45%
254
'Mr/ 1
41
7 was not possible to completely review the financials of the company. However,
based on the findings in JDW-II and JDW-III, a similar exercise was conducted
7 regarding the assumption of plant factor of 45% used in the tariff determination and
was corroborated with the actual plant utilization (annual Net Electrical Output) as
per information provided by CPPA-G. Details of findings are as follows:
The actual recovery of such cost is linked with actual energy production rather than
plant factor determined at 45% by NEPRA. Details of the excess gains earned by the
project aggregating to Rs. 1,337,081,467
on this account is tabulated below:
255
ANNEXURES
No. IPP-01(12)/2017.
Government of Pakistan
Ministry of Energy
(Power Division)
NOTIFICATION
Subject: Committee for PowersecterAUdlt.ClrcuIaLUebt Resolution_udi uture Readmit')
The Competent Authority Is pleased to constitute a Committee with the objective to identify and
examine the causes of the high cost of electricity in Pakistan, Including relafion to the establishment of private
power generation units under various power policies and propose steps to rectify any wrongdoings of the past
and ensure the future energy security of the county. Additionally, the Committee shall identify and examine
the causes of the circular debt which has accrued In the power sector of Pakistan, and propose a way forward
to address the outstanding circular debt as well as interventions to prevent future build-up of the circular debt
and to ensure supply of power at the least possible rates.
a. Review matters pertaining to the cost of setting up private power generation units in the
county under various power policies including, without limitation, whether under WP mode or
under government ownership, approvals, financing arrangements, set-up cost, cost over-runs
if any, operating Cost and cost Models, revenues and retum models, billing, cost to the
government role of govemment, its departments and various regulatory bodies etc., and
Identify any unethical or illegal practices, administrative procedural weaknesses and regulatory
gaps that may have taken place and recommend the way forward to rectify these;
le
256
Review matters pertaining to the 'circular debt' in the country, including, without limitation, the
cause of build-up of 'circular debt', examine payments made from time to time to clear
outstanding dues to the Independent power producers, examine causes for under collection of
revenue by DISCOs, electricity tariff determination policies and procedures, systemic issues
which may have exacerbated the situation, etc., and identify any unethical or illegal practices,
administrative and procedural weaknesses and regulatory gaps that may have taken place and
recommend the way fonvard to remedy these;
Review policies and models of power sector globally and recommend the way forward for
changes in the country's power policy and structure of the sector, including, without limitation,
generation, transmission, distribution, organizational set-ups, regulatory reform, governance
reform, financial clearing, market-based mechanisms, etc., with a view to ensure avoidance of
circular debt in the future and reduction of cost of power to consumers;
To review the compliance of IPPs with parameters and terms and conditions of various
agreements signed with relevant Government Agencies / Bodies which shall include, without
limitation, the under mentioned areas: -
1. Any relaxations given to IPPs In violation of policies / rules, including but not limited to:
Tariff determination
Financial closure
Construction period
Capacity payments
Merit Order, etc.
ii.
Efficiency (Machine as well as plant / fuel) allowed in tariff and actual efficiency,
frequency of efficiency verification, fuel costs and inventory etc.
in.
Cost accounting mechanism and review of various cost components; and
iv.
Review of technology, capital costs and financial structure submitted for tariff
determination.
5. The
Committee to submit phase-wise findings / reports, from start date, to Prime Minister as
under:
First Interim Report will be submitted within a period of six (06) weeks;
Second Interim Report will be submitted within a period of ten (10) weeks; and
Final consolidated report will be submitted within twelve (12) weeks.
B.
Following logistic support shall be provided to the Committee for efficient and smooth functioning:
257
Annexure B - Presentations and Meetings
K-Electric
NAB Lahore
NAB Rawalpindi
I
Mr. Omer Ayub - Federal Minister for Energy I
1
Mr. Mad Umer - Federal Minister for Planning, Development, Reforms and Special Initiatives
258
Mr. Tauseef Parooqi - Chairman, NEPRA
259
Energoprojelct Entel- Dubai
Representatives of USAID
260
Annexure IA - IPPs: Sponsors, Location and operations
17 Pakistan WAPDA
01 Oddu Paver Company Ltd tot Adds,. District
KAPCO Employees
Muria faroarh, 1638
Empowerment Trust Gas & RFO 1994
Punjab Dec 1996 25 Dec 2021
LO I
-•. 4th Apr 2039 I 19
Dela Muratd 4. Apr 2014 25
Low BOiGas 2002
JaniAL 404
Engie France I
31 Uchal Power Pvt Ltd. Baluchistan 30 8... Nov 2047 21
Hydro 2002 Bo Nov 2017
Muzarlarabad, MK ; 147
KOS Hydro PTE Ltd.
32 Star Hydro Power Ltd.
lybal AA Muhammad / Inituctu 50 Mod RE 2006 16. Sept 2016 20 16th Sept 2036 16
Amoy
46 Metro Power Company Ltd Aua Keeryhai Win
kraal Ma Mulummad /
Gul Ahmed Wind Power Ltd. INERACOAISA / International lhimpr 50 Ws/ RE 2006 18., Oct 2016 20 11. Oct 2036
50 , 16
Finance Corporatton
Hussain Dawood group Chant 49.5 W51d RE 2006 lluOct 2016 20 55..tattrat t 16
51 renege Generasi Ltd.
HydrochlirialrrirrilalionidI
49 5 Wind RE 2006 Su April 2017 20 Apt 2031 17
Hydro China Dawood Power PA Ltd Engineering Co. Ghana
52
Raligue Dawood
Super Success Investments Wind RE 2006 16. lune 2017 20 16u, June 2037 17
UEP Wind Power PH Ltd. Ihmpr 99
54 Limited • Mauritius
China Three Gorges South RE 2006 30uthine 2018 20 30. June 2038 18
5, Three Gorges Pakistan Second Wind Jhimpir 495 Wed
Farm Pakistan Ltd. Ada investment limited
262
59 Then Gorges Pakistan Third Wind
Farm Pakistan Ltd. China Three Gorges South
Asia Investment Limited
96 July 2038 18
60 Tricon Boston Consulting
Corporation Pvt Ltd. A Sapphire group Thim pi r
16th Aug 2038 18
61 Triton Boston Consulting
Corporation Pvt Ltd. • B Sapphire poup
14.5ep4 2018 144, Sept 2038
62 Triton Boston Consulting 18
Corporation NI Ltd.. C Sapphire group Rinpir
116 Sept 2018 116 Sept 2038
63 Zephyr Power Pvt Ltd. 18
Zia Rhein' 1
RE 2006 278 Mar 2019
64 QA Solar Posner Pvt Ltd. T/8 Mar 2039 19
Government of Punjab QASP
Bahawalpur RE 2006 15,July 2015 1S8 July 2040 20
65 Apollo Solar Development Pa/datan
Ltd. Apollo Solar Develowneid
QASP
Hong Kong ' ilibawalpur 310 May 2016
I 31*May 2011 21
66 Bel Green Energy Pakistan Ltd.
Best Green Energy Limited GASP
Bahawalpur 31*July 2016
67 314 1uly 2041 21
Great Energy Pakistan Ltd.
Crystal Entry Poldsisrl
68 Herappa Solar PA Ltd. 314 July 2016 25
Rana Hamm Ahmed 31*Iuly 2041 21
69 A.1 Power Ph Ltd. 148 0ct 2017 25
Minsk Tanen group: 148 Oct 2042 22
70 Oursun Pakistan Ltd. 13$ Dec 2017 25 136 Dec 2042
Nadeem Baba 22
71 MW Sup: NIS Ltd (Unit-110 128 May, 2018 25
Kingly Tamen group! 128 May, 2043 23
72 1DW Sugar Mills Ltd (UnIt-111) 12.,
'than& Tanen group _ June 2014
. 30 120 June 2044 24
73 Chinn Power Ltd. Sideman 8liabbaz Shan 3NOct 2014 30 314 Oct 2044 21
group Bagasse
74 RYK MIN Ltd. RE 2006 2.58 Nov 2015 30 286 Nov 2045 25
Makhdum Omar Shahryar Rahim Yar Khan
75 Hama Sugar WIN 11413444. RE 2006 248 Mar 2015 30
Khanpur 244I hi ar 2045 25
Min Muhammad Tay*
Rahlmyar Khan Bagasse R12006 _
76 Layyah Sugar MI% 108 tvlar 2017 30 104 Mar 2047
Shamhn KhAn • 27
77 UY7411 Bagasse RE 2006
Al Mole Induttrin Limited Dec 2017 30 le Dec 2047
Shandm Man !Spin ?Hamill 27
78 Baps" RE 2006 48Jan 2019
Charier Energy Limited Tandlanw aim 30 48 8in 2049 29
laved Ahmad Kayarti
Fabalabad Banana RE 2006 156 Feb 2019 30 15th Feb 2049
i
29
Grand total 19,101
r--
263
Annexure 1B — 2002 IPPs: Sponsors, Location and Operations
i
Name of 1PP
i I
1 Atto3c Gen Ltd. Mock group MorgahRawallindi 165 RIO 173Z9 25 14
2 Atlas Power Ltd. %taxi group Sheikhupura, Punjab 225 itro 18.122009 25 11
3 Engro Energy Ltd. Hussain Dawood group Qadirpur, District Cimtld, Skutt 227 Low Btu Gas 2712010 15 15
4 0-Purer Ltd:—--- S gro
5 Halmore Power Generation Ca Ltd. Mian Karimuddin family Bluid, District Sheihupura, Punjab 225 Gas/RING 16.61011 30 21
6 Narowal Energy Ltd. Hatlan group Narowai Punjab 220 RIO 22.41011 25 16
7 Liberty Power Tech Ltd. Mulmty group Faisalabad (near M3 Industrial State) 200 RIO 131.2011 25 16
8 Nishat Power Ltd. Mansha Group near Lahore 200 RIO 9.6/010 25 15
9 10shat Quinlan Ltd. Manilla Group near Lahore rio RIO 2171010 25 15
10 Orient Power Company Ltd. Nadeem Babar Balloki, District Kasur, Panjab 229 Gas/RING 2452010 30 20
12 Sapphire Bernie Company Ltd. Sapphire pup Muddle, District Sheikhupura, Punjab 225 Gas /RUC 410.2010 30 20
13 Uch41 Power (Pvt.) Ltd. Engle France Dera Murad Jamali, Baluchistan 401 Low Btu Gas 4.41014 25 19
14 Star Hydro Power Ltd. IOS Hydro Muzaffarabad, AJK 147 Hydel 8.11.2017 30 27
Total 3,081
* Star Hydro Power Ltd. was the only hydro-based plant under this policy. However, it
' could not be reviewed as NEPRA has not finalized the COD determination till the time
of submission of this report.
264
Annexure 1C - Heat Rate res wig Parameters
WARTSILA
265
156 138 kW Combined Cycle Power Plant
WARTS1LA for Attock Gen Ltd.
1. Introduction
To clarify the influence of the quality of Fuel, Site Conditions, Ageing on the equipment used for
the Attack Gen Limited's Power Plant the following parameters have an impact on the
performance of the Power Plant during its 25 years Life Cycle:
Note: The values given for Heat Rates and Efficiency on Wiirtsili Web Site or in
Brochures are always including a 5% tolerance and are related to ISO Conditions
values can only be used as e euarantee if the
and at Generator Terminals. These and the Site Reference Conditions are equal to
guarantee Includes the 5% tolerance
the ISO Conditions and the eauloment are new and clean. For the Attack Can
Limited Power Plant the ouaranteed tames are without tolerance (0%) and related
to the Site Reference Conditions annlicable to the Attock Gen Limited Power Plant
for a period of 25 years.
The fuel to be used to operate the Power Plant is Residual Fuel Oil (RFO) produced by Attock
other sludge components are highly
Refinery from indigenous crude. The content of water and
depending on the quality of the composition of the fuel. As the fuel might vary in quality from
of the Heat Rate, the
time to time an average of 2% sludge shall be used for the calculations
Efficiency and the Specific Fuel Consumption (SFC). The 2% sludge is based on Wensiirs
emiceicsi,c revu 11il nSlallaiimis upending wit aiiniint fuel in Fakiattut anti in eat of
world.
The 2% Sludge therefore increases the value of the Heat Rate and SFC, which results in loss in
Efficiency, when calculating on basis of actual used fuel.
15.7.2007
LarvAke Kjell I Power Plants Page) of 5
266
a
•
2 45,5 ‘ \ 7.\
, ‘
I\\. IS
, \
I\
\ Ageing variation 4%
I"
I . 7 . t , i I \
.. \ I
T
al ,D , - Life Cycle Efficiency: Average 2%
7
45,00 N
/ \ I I • S . ' I
Ex 44.5 ; ' N. I %\ IA n.. .1 \• / . •. \. 1
0 1 .\ I .. "1 \I \ i -. \ I .. \ .1
0 44,0 . N v 4.
43,5 I
42,5
New
lid On 5th
Ovelgallig
j New I. Clean - - - Sludge 2% --- — Ageing variation 4%-Avenge 2%
--Life Cycle Efficiency I
The conclusion is that during the Power Plants Life Cycle period of 25 Years, the Output of the
Power Plant remains unchanged (156 138 kW at Site Reference Conditions) however the Fuel
Consumption (1(2/11) must be adjusted to the Site Reference Conditions as well as the Heat Rate
and
SFC. In addition the Heat Rate will deteriorate (3% average) due to Ageing and the Sludge
(2%) must be separated from the fuel.
This brings the Efficiency down from 46.88% (New 8: Clean with clean Fuel) to the. Life Cy&
Efficiency of 45.0% (7 999 IclikWh). This Life Cycle Efficiency is based on operation at full
Output of the Power Plant and does not account for losses in Efficiency suffered due to (i)
tipteeg;thia ;ii 2;i1ndc [gide guide,
Sicuiciniupc Slid (in) upci talons ai uulputs whieb are knoci
than full Output of the Power Plant
15.7.2007
Lan-Ake Kjell I Power Pima Page 5 of 5
Annexure 1D - Summary of Available Financial Statements for 1994
IPPs
tuantal tuttenn Subound tot dn. inn
CompurrNom Mb 2016 2017 2111 311 PS equited %ad FS
L 147.9 370 341 3,72 1101 161 365 mos NY MOS 309 311 XIII 3112 413
COO Pau Mn 0191 541... COD it. FL,
I V / I i 1 1 1 1 1 1 .1 ./ I 1 I V 1 I r 1 r 11 13
It.61 Addc Met 1,038 II) I Doc So
20.11.0 / 1 r' i / V / 1 I V 1 I 1 V 1 / 1 1 1 1 1 / 21 21 0
Nakao ENItT 1131 1:111
Twitter. limped (Ili 11161 204un-9 r i i 11111111:10113111 i i i 1 I V V r 1 1 1 V 1 1
268
Annexure 1 E - Wind Tariff Regimes under 2006 RE Policy
Subsequent to the 2002 Policy, NEPRA issued a cost-plus tariff for wind technology under
which seven IPPs totaling 355 MW have achieved commercial operations till date. Salient
features of this regime were:
The
cost-plus tariff was determined on the basis of RoE based
on USD /RR of 17%.
The tariff under the cost-plus regime was a single-pad tariff (unlike two-pad tariff -
CPP and EPP - in 2002 policy), to be paid on the basis of actual energy produced.
In order to
ensure payment of fixed costs, a
certain minimum production
benchmark (varied based on the site, ranging between 31% to 33.12%)
agreed was
with payment of debt, interest cost, O&M
and insurance, being ensured
up to this benchmark production level, irrespective of actual power production.
For production beyond the benchmark, the power
producer was to be paid 10%
of the tariff.
fl
The wind risk was assumed by the power purchaser.
The Wind Upfront Tariff was introduced on April 24, 2013 under which eight companies
have successfully achieved commercial operations. It was based on the average of the
project costs excluding IDC from the applications submitted by eleven companies that
had earlier sought cost-plus tariff. Salient features of this regime were:
269
cost, O&M and Insurance; however, there was no minimum payment guarantee
by the power purchaser.
In case the Net Annual Capacity Factor exceeded 31%, a mechanism was
provided for sharing of tariff between the power purchaser and power producer,
as per the following table:
% of tariff fo
Net annual plant capacity factor . producer
Above 31% to 32% 75%
Above 32°/o to 330/a 50%
Above 33°/o CO 34°A , 25%
Above 35% 100/0
Subsequent to the lapse of the upfront wind tariff, NEPRA facilitated the development of
wind power generation by issuing a new Wind Upfront Tariff vide decision dated June 24,
2015. Nine companies opted for Wind Upfront 2015 tariff and all of them achieved
commercial operations. Its salient features were:
The maximum construction period was up to 18 months while the tariff was
applicable for a period of 20 years from the commencement of operations.
It included RoE based on 17% USD !RR
Wind risk was also borne by the power producer.
The Net Annual Capacity Factor was fixed at 35%, and if power production
exceeded 35%, the tariff was to be shared between the power producer and
power purchaser as per the following table:
270
Annexure IF - Solar Tariff Regimes under 2006 RE Policy
NEPRA issued a unit-delivered based upfront tariff for solar photovoltaics technology on
January 21, 2014 for projects between 1 MW to 10 MW with a maximum induction
capacity of 50 MW. The tariff was valid to be opted by prospective power producers for
a period of up to 6 months from the date of determination, which was later extended.
Six IPPs opted for Solar Upfront 2014 tariff, however, no IPP achieved CoD under this tariff.
Salient features of this tariff are as follows:
•
The targeted maximum construction period for each project was 8 months.
Tariff was based on 18% equity USD IRR and was valid for a tariff control period
of 25 years.
The annual net capacity factors for north and south regions were determined
as 16.78% and 17.5%, respectively. Power produced beyond the net capacity
factor was required to be shared between the power producers and
power
purchaser as prescribed in the determination.
Producers were able to
cover their cost of debt, interest, insurance, O&M and
earn RoE based on
18% USD IRR at the net capacity factor of their production.
The following project cost was
approved for a 10 MW solar PV based project:
USD
million/NM
1.69
0.13
0701_ _
1.84
0.05
0.02
19.01 1.90
271
Solar Upfront 2015 - I
In 20151 after the lapse of Solar Upfront 2014 tariff, NEPRA issued another upfront tariff on
January 22, 2015 for solar plants ranging from 1 MW to 100 MWs. This tariff was determined
by NEPRA on the basis of information provided by Quaid-e-Azam Solar Power (Private)
Limited. This tariff was valid to be opted by prospective power producers for a period of
_J
up to 6 months from the date of notification of the tariff. Seven IPPs opted for the said
The tariff control period envisaged in the tariff was 25 years and the return allowed
was 17% equity !RR.
The risk of solar irradiation was to be borne by the power producers and plant
capacity factors were determined as 16.78% and 17.5% for north and south
regions, respectively.
Any generation beyond these benchmarks was considered to be shared as per
the following mechanism:
,.
Net Annual Plant Capacity Vac -
Above 16.78%/17.50% to 17.78%/18.50% 75%
Above 17.78%/18.50% to 18.78%/19.50% 50%
Above 18.78%/19.50% to 19.78%/20.50% 25%
Above 19.78%/20.50% to 20.78%/21.50% 20%
Above 20.78%/21.50% L 10%
The following project costs were approved by NEPRA for the various categories as
presented below:
272
Solar U ront 2015 - II
Towards the end of 2015, after recognizing the significant improvement in technology
and the resultant reduction in equipment cost, NEPRA initiated suo-moto proceedings for
the development of another upfront tariff for solar which was issued on December 16,
2015. This tariff was made applicable from January 1, 2016 and prospective power
producers could opt for it till June 30, 2016. Three IPPs opted for Solar Upfront 2015 - II tariff
and all three have achieved CoD.
' I kl:°L.I.L111 4
A of prevalent tariff
Above 17%/18% to 18%/19%
80%
Above 18/190/. to 19%/20%
90%
Above 1934/20%
100%
me
roirowing project costs were approved by NEPRA for the various categories as
presented below:
273
>50 MW $100 MI. UAW;
Description USD rnillidn/MW
1.07 1.09 1.11
EPC
0.07 0.0t 0.07
Non-EPC
1.14 1.16 1.19
CAPEX
0.03 0.03 0.03
Financing Fee & Charges
0.01 0.02 0.01
IDC
1.19 1.21. 1.23
Project Cost
In 2017, subsequent to the lapse of Solar Upfront 2015- II regime, NEPRA recognized the
benefits of competition, therefore, on March 3, 2017, it directed the relevant agencies to
carry out competitive bidding process for award of tariff to new solar PV power projects,
274
_
Annexure 1G - Excess Profits: Miscalculation in !RR
_
Excess RoE -to
Excess RoE be paid over
Paid to Date Remaining Total
Concession Life
Eint
nam.... 1.11111
__ NII 5 Rs Billion
25
tialln t0.1.1.1.
wer Genera m CmnPmY 7.13
Ltd. a 30
Narowal Energy Ltd. 433 5.02
8 25
295 3.58
30
Offic 8 3.39 3.97
30
Orient Power Compimy Ltd 4.28 4.78
9 30
Z23 8 4.10
1 25
Engro Power Gen QadirPur Ltd. 2.15 2.66
9 25
1=
rimmminrmmm.mmm..._ 2.04 2.60
11 8 25
wasissaassaamEmminninil
- - 2.13 2.60
Nishat Chunian Ltd. 2.24
8 25
Foundation Power Company paharld) Ltd. 2.15
8
ISMEEM 0.4 2.13
9 25 233
I 0.36 1.35 L71
Power Polley 2006 (Wind) 646
45.07
1 Zodu Energy Mateo Ltd
2 6 20 0.35
Foundation Wind Energy-11 Pvt. Ltd 1.67_
5 20 0,27
3 Sapphire Wind Power Company Ltd. 1.78
4 20 0.21
4 Foundation Wind Energy-1 Pvt. Ltd 1.70
5 20 0,22
5 PVC Energy Ltd. 1.72-
6 20 0.26
6 Three Gorges First Wind FalITI 1.56
5 20 0.19
7 Hydr0 Chine Dawood Power Pvc ltd. 1.43
Total 1.98 2.06
Power Policy 2006 (Solar) 11.39 li97
1 QA Solar Power Pvt. Ltd. 4 25 0.3 146
2 Apollo Solar Development PaldStEl Ltd. 3.76
3 Crest Energy Pakistan Ltd.
4 Best Green Energy Pakistan Ltd.
MM' 3 25
0.14
0.12
2.65
3.15
2.43
Total
0.72 11.26 11.98
Power Policy 2015
275
Annexure 1H - Excess Payments: Mismatch in Debt Payments and
Inventory Shortfall
- - ,
ears in,
Operation Mismatch in Debt ,
Company Name Since i Payments
, COD ,
4
Power Policy 2002
9 0.14 -
1 Attack Gen Limited
8 0.2 0.64
2 Liberty Power Tech Limited
8 0.21 0.57
3 Nishat Chunian Power Limited
i
80.2 0.22
4 Nishat Power Limited
5 0.09 -
5 UCH-II
8 0.22 0.97
6 Atlas Power Limited
Engro Power Gen QadirPur Limited 9 0.12
7
Foundation Power Company (Daharki) Limited 8 0.15
8
Sapphire Electric Company Limited 9 0.17
9
Saif Power Limited 9 0.19
0
Orient Power Company Limited 9 0.124 -
11
12 Natowal Energy Limited — HUECO* 8 0.18 1.22
13 Halmore Power Generation Company Limited 7 0.14 -
Total Total 2.14 3.63
276
r--
Annexure 11 - Shifting to TaP: Impact on CPP in 2018-2019
1
pacify Payment ; Plant Factor/ Savings due to ;
^ (Its. billion)* Utilization (%) * TaP
Its. billion
2.35
3.17
-far
2.45
2.45
0.48
2.14
23
0.64
0.58
1.59
8.38
* 28.18
Actual capacity payment FY 2018-19 with actual plant facto
Note:
This saving is calculated for plants set up under 2002 Policies and one plant under
the 2015 Policy.
277
Annexure 1J - 1994 and 2002 IPPs: Years of Operation
Years since
Power Policy 1994 Fuel COD COD
RFO -Feb-98 22.10
Pak Gen. Power Limited
RFO 6-Nov-97 22.33
2 Lal Pit (Pvt.) Ltd
RFO 3-Nov-97 22.34
3 Gul Ahmed Energy Limited
RFO 14-Mar-00 19.98
Japan Power Generation (Private) Limited
RFO 20-Jun-97 22.72
5 Kohinoor Energy Ltd
RFO 11-Dec-99 20.24
6 Rousch (Pakistan) Power Limited
RFO 31-Dec-99 20.18
7 Saba Power Company Limited
RFO 12-Jul-99 20.65
8 Southern Electric Power Company Limited
RFO 20-Jun-97 22.72
9 Tapal Energy Limited
Gas 6-Jun-01 18.75
10 Altem Energy Limited
Gas 21-Oct-99 20.38
11 Fauji Kabirwala Power Co. Ltd
Gas 13-Jul-13 6.64
12 Davis Energen Power Project
Natural Gas 11-Sep-99 20.49
13 Habibullah Coastal Power Co. (Pvt.) Ltd
Natural Gas 10-Sep-01 18.49
14 Liberty Power Project
Low Btu Gas 18-Oct-00 19.38
15 Uch Power Limited
Kot Addu Power Co. Ltd Gas 1-Dec-96 23.27
16
Years since
Power Policy 2002 Fuel COD
COD
Attock Gen Limited RFO 17-Mar-09 10.97
2 Atlas Power Limited RFO 18-Dec-09 10.21
3 Narowal Energy Limited RFO 22-Apr-11 8.87
4 Liberty Power Tech Ltd RFO 13-Jan-11 9.14
5 Nishat Chunian Power Limited RFC 21-Jul-10 9.62
6 Nishat Power Limited RFO 6-Sep-10 9.49
7 Saif Power Limited Gas / RLNG 27-Apr-10 9.85
278
1_
Note:
These recommendations are on the basis of Tentative Dispatch Plan 2020 prepared with help of SDDP Software by
N'TDC
Final decision may be taken only after carrying out detailed technical study
F
279
Ir
-J
For a period equal to the lesser of (i) five (5) years and (ii) the remainder of
the initial term of the Power Purchase Agreement, an amount equal to the
Net Cash Flow, expressed in dollars, for such period, discounted to its
present value by applying a discount rate equal to ten percent (10%) to
the base case pro forma presented to the lenders at Financial Closing plus
the Net Cash Flow under any supplemental tariff.
3. In case of As and PPAs executed for projects implemented under the 2002 policy, --J
the Federal Government is required to pay elements (a), (b), (c) & (d) of the
Compensation amount to the concerned IPP in case the said IPP opts to terminate
the IA owing to Federal Government Event of Default.
280
4. A brief description of the components is provided below:
For a period equal to the lesser of (i) four (4) years and (ii) the remainder of
the initial term of the Power Purchase Agreement, an amount equal to the
Net Cash Flow for such period, discounted to its present value by applying
a discount rate equal to twelve percent (12%) shown in the audited
financial statements of the Company for the last completed financial year
prior to the date of termination.
5. Based on the above discussed terms of the As, the Committee has included
financial analysis of components (a) (b) (c) and (d) required to retire certain
plants.
Ii
to be made by it
281
hereunder or under the Guarantee on the due date for payment specified
herein or in the Guarantee that continues unpaid for thirty (30) days:
7. Similar provisions (E0Ds) are also included in the As executed with regard to the
project established under Power Policy 1994.
282
Annexure 1M - IPP-wise detailed analysis for Retirement of Plants
For details of these plants and justification for their closure, please refer to Annexure 1K.
As per Section 9.1 of the PPA, AGL shall be paid capacity payments based on "Available
Capacity". As per the payment data provided by CPPA-G for the previous years,
capacity payment has been made for the following components of the tariff
determination:
Working Capital;
RoE; and
RoEDC.
F-
Similarly, debt service was also paid as part of capacity payment. Based on the available
payment data from CoD till June 30, 2019, the growth rate for the components of Fixed
O&M Foreign and Fixed O&M Local has been estimated. For working capital, payments
were assumed to be static based on the last year payment, whereas RoE and RoEDC
were estimated assuming that USD appreciates against PKR at an average rate of 6%
per annum (actual yearly depreciation was around 6.87% during last 9 years). Based on
these assumptions, the future capacity payments to be made are:
7,022,786,063
-
6,496,812,876
2,768,894,020
35,956,594,120
283
Termination costs reauired to be bald
Based on the compensation clauses discussed in the Annexure IL, components (a), (b),
(c) and (d) of the compensation clauses were calculated. As the company has already
retired its debt, component (a) was assumed to be Nil. Similady, component (d) was also
considered to be Nil as, based on the information available with the Committee, none
of the IPPs under 2002 policy injected additional equity into the companies. Component
(b) was calculated based on the formula discussed in the previous section and
reproduced below:
"as of the date of transfer of the complex to the Federal Government, the actual
initial equity investment in the comp/ex, not to exceed the equity investment
approved by the Federal Government in relation to the Financial Closing, reduced
on a straight line basis from the Commercial Operations Date through the term of
this Agreement to twenty percent (20%) of the initial value of such equity number
available in CoD determination of tariff..."
Component (c) was calculated based on the formula discussed in the previous section
and reproduced below:
"for a period equal to the lesser of (i) four (4) years and (ii) the remainder of the
initial term of the Power Purchase Agreement, an amount equal to the Net Cash
Flow for such period, discounted to its present value by applying a discount rate
equal to twelve percent (12%) shown in the audited financial statements of the
Company for the last completed financial year prior to the date of termination."
Termination.
Lenders a
_
NEPRA CoD determination.
Equity b 1,197,273,088
Equity of Rs. 2,494,318,934
Audited financial statements for year end June .30,2019.
Net cash flow c (642,854,989)
Net caah flow Its. (211,650,000)
Additional equity d -
Total 554,418,099
284
Similar methodolo • for calculation of Ca •
acit a ments and Termination cost as
used in the case of AGL has been a • •
lied to the calculations for other tants.
Fixed payment 0
6.19% 15 8,190,497,545
15 7,726,218,875
4,296,697,500
USD - PKR 6%
30,989,994,215
15 3,334,940,830
Total 54,538,348,966
ennination
Lenders
_EquitY 2,585,158,800 NEPRA CoD detenninseion. Equity of USD
63,850,000 x USD/PKR 84.35 = Rs. 5,385,747,500
Net cash flow
(337,112,367) Audited financial statements year end June 30,2019.
Net cash flow Rs. (n00)
285
Liberty Power Tech Ltd.
Remaining Future
Annual growth, years paynAA
CFP components rate
Rs.
Debt Service Fixed payment 1 2,586,589,234
Fixed O&M 6.19% 16 9,376,819,074
F_Lnir:
ign
Fixed O&M Local 5.700/c 16 5,829,008,118
Working Capital Fixed payment 16 4,043,847,247
ROE USD - PICA 6% 16 29,403,514,851
ROEDC USD - PIM 6% 16 4,681,171,591
Total 55,920,950,114
286
Nishat Chunian Power Limited
cQQQcfty payments expected in future
Ti
Remaining i
_years
Future 7
payments
Debt Service Rs.
Components
Source
Equity _
2,080,959,283 NEPRA Con determination. Equity of USD
47 481 000r USD/PKR 85.6 = Rs. 4,064,373,600
Net cash flow
Audited financial statements YE June 3Q 2019. Net
cash flow Rs. 063 549 000
287
Annexure 2A - Cumulative Budgetary Support to Power Sector
Budgetary Subsidies Released to Power Sector
FY2007 FY2008 FY2009 FY2010 FY2011 1 F12012 , FY2013 FV2014 FY2015 FY2016 FY2017 FY2018 FY2019 1 Total
1
Rs billion
TO WAPDA/ PEPE()
17.55 87,00 8230 93.49 245.83 412.02 250.06 363,15 174.00 128.59 91.08 j 48.75 130.00 2123,52
Inter Disco tariff differential
1733 21.31 3.02 5.70 4.00 1 - 51.96
Adjustment of additional surcharge against GST
10.00 10.00 7.00 10.00 10.00 18.87 9.90 j 9.14 12.00 96.91
Pick up receivables from FATA
30.20 38.95 - 69.15
Interest payment on TFCs
2.93 3.69 4.00 5.04 3.00 1.00 10.62 j 1.68 - 4.86 36.82
Agriculture Tube wells in Balochistan
3.52 1.70 1.44 2.16 8.81
Other Subsidies
41.93 113.69 90.45 146.59 298.78 419.02 1 260.06 366,15 185.00 158.08 : 102.66 1 57,88 146.86 2387,17
TOTAL
10 KB
13.74 15.69 17.00 31.71 46.00 45.00 84.00 64.00 3630 53.40 10,08 10.98 13.15 440.76
Tariff differential
2.79 3.45 1.28 0.23 1.00 8.76
Adjustment of additional surcharge against GST
0.41 0.45 0.44 0.31 0.32 , 032 ' 0.60 j 0.39 0.49 3.72
Other Subsidies
16.94 19.60 18,72 32.25 47.32 45.00 84.00 64.32 36.00 53.40 10.68 , 11.37 13.64 I 453.23
TOTAL
58.87 133.28 109,17 178.84 346.10 i 464.02 686.02 430.47 221.00 211.48 1 118.00 83.98 160.50 3,201.74
GRAND TOTAL
288