Adani Power Limited (C): Renegotiating Long-Term Energy Contracts

Abstract

This three-part case series covers a period of over three years during which Adani Power Limited, an independent power producer in India tried to obtain financial relief after having entered into three long-term contracts of 25 years to supply electricity at a fixed price for a total capacity of 3424 MW.

This case was prepared for inclusion in Sage Business Cases primarily as a basis for classroom discussion or self-study, and is not meant to illustrate either effective or ineffective management styles. Nothing herein shall be deemed to be an endorsement of any kind. This case is for scholarly, educational, or personal use only within your university, and cannot be forwarded outside the university or used for other commercial purposes.

2024 Sage Publications, Inc. All Rights Reserved

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Resources

Exhibit 1: Structure of the Indian Electricity Sector 1

After the enactment of the Electricity Act in 2003, the electricity sector in India mostly stands unbundled with generation business free from licensing requirement. Distribution and supply business is an integrated business in the hands of unbundled distribution companies, which are licensed to distribute and supply electricity in a given geographic area. Each state has its own unbundled transmission entity called “state transmission utility” or STU. Inter-state transmission assets are created and maintained by the central transmission utility, viz., PGCIL – a central government owned firm. Distribution companies procure electricity either directly from generators or from electricity traders under the broad supervision of regulators. Each state has a regulator (State Electricity Regulatory Commission, SERC) having jurisdiction over the entities operating exclusively within the state. The Central Electricity Regulatory Commission (CERC) exercises jurisdiction on issues affecting more than one state. Scheduling and dispatch of electricity is done by a three-tier system of system operators – National Load Dispatch Centre, Regional Load Dispatch Centre, and State Load Dispatch Centre. Distribution companies can procure electricity through long-term bilateral or multilateral PPAs, short to medium term contracts with generators/trader or from market. Transmission utilities are expected to provide open access to generators and distribution companies under long-term, medium-term and short-term open access regulations enacted by the CERC. Consumers at large get their supply from their distribution company, which is the default supplier. Qualified large consumers can opt for open access to distribution systems by getting their electricity from a trader/generator or whole sale market. There are two power exchanges (PXI and IEX) working in the country but most of the electricity dispatched is based on longer-term contracts.

Exhibit 2: Procurement of Electricity by Indian Utilities 2

After India gained independence in 1947, the Indian Electricity Sector evolved under the legal framework provided by the Electric (Supply) Act of 1948. The act envisaged the creation of State Electricity Boards (SEBs), one each for most of the states, owned by the state governments and operating as vertically integrated utilities. Consequently, each SEB had its own generation, transmission and distribution system covering the geography of the state/province. A few of the private sector licensees operating in the urban centres of Mumbai, Kolkata, Ahmedabad, and Surat were allowed to operate as a distribution licensee on the basis of the license given to them prior to India’s independence. By the 1970s, the Central Government created generation entities such as NTPC, NHPC, DVC, NPC, etc. to supplement the generation capacity partly to optimally locate such capacity near pit-head or primary energy sources and partly to make up for the inadequate capacity addition and poor operating and financial performance of SEBs. After economic liberalization and due to pressure on public finances, SEBs were allowed to contract for generation capacity from IPPs (Independent Power Producers) in 1991/92. While initially the private sector and multi-nationals showed considerable enthusiasm, actual capacity addition did not take place as envisaged due to the poor financial condition of the SEBs and the buyers. Initial attempts to unbundle and privatize the distribution in Orissa failed as the true extent of technical and commercial losses being incurred by the SEBs was revealed. A series of reforms aimed at independent regulations and restructuring of the sector culminated in the enactment of the Electricity Act of 2003. The act mandated unbundling of integrated utilities, and distribution companies were carved out of existing SEBs. A carved out distribution company inherited existing capacity contracts/arrangements with the generation entity carved out of the SEB and with other generators such as NTPC, NHPC, IPP, etc. Till 2005, there were no explicit and uniform guidelines on how a distribution company should procure. Some of the IPPs were contracted on an MoU basis without any competitive bid. Central Government owned entities such as NTPC, etc. continued to add capacity on the basis of “cost-of-service” regulations.

In 2005 3 , the Central Government issued guidelines for procurement of electricity by distribution companies. The guidelines were made applicable for procurement of power over the medium-term (1-7 years) and the long-term (more than 7 years). The procurement was classified into categories: “Case- 1, where the location, technology, or fuel is not specified by the procurer; and Case-2 for hydro-power projects, load center projects or other location specific projects with specific fuel allocation such as captive mines available, which the procurer intends to set up under tariff based bidding process” 4 . The guidelines required the procurer (Distribution Company) to follow a two stage process consisting of RFQ (Request for Qualification) and RFP (Request for Proposal). The bids were to be invited based on a multi-part tariff structure consisting of capacity and energy charges to be quoted separately (for details, see Exhibit 2). However, the single-part tariff bid structure with a single-stage bid process was allowed for medium-term procurements. Based on the quote of a bidder and the discount rate and projection of indices (for escalable component of capacity and energy charges) given by CERC, a levellized tariff over the term of contract was computed for each bid. The lowest bidder, in terms of levellized tariff, was awarded the contract. While procurement from private sector companies in generation had to be procured on the basis of these guidelines, procurement from Central Government owned entities such as NTPC, etc. (where tariffs are determined on the basis of “cost-of-service” regulations by CERC) could be done for a further period of five years without inviting competitive bids.

Exhibit 3: Loss Estimation on Gujarat PPA from SCOD till 31st March 2013

Particulars

Unit

FY 11-12 (from 2 Feb 2012)

FY 12-13

Total from SCOD to 31 March 2013

PPA sale

MUs

609

4100

4709

Total PPA Revenue

Rs. Cr.

134

921

1055

Quoted Capacity charge per unit

Rs./unit

1.00

1.00

Net Realized Capacity Charge Per Unit*

Rs./unit

0.813

0.854

Quoted Energy charge per unit

Rs./unit

1.35

1.35

Total Fuel Cost

Rs. Cr.

139

983

1122

Capacity cost per unit

Rs./unit

2 .39

1.79

Energy cost per unit

Rs./unit

2.28

2.40

(Source: Committee Report to CERC for determination of compensatory tariff in the matter of Adani Power Limited, August 2013)

Exhibit 4: Loss Estimation on Haryana PPAs from SCOD till 31 March 2013

Particulars

Unit

FY 12-13 (from 7 Aug 2012)

PPA sale

MUs

2712

Total PPA Revenue

Rs. Cr.

631

Quoted Capacity charge per unit

Rs./unit

1.155

Net Realized Capacity charge per unit *

Rs./unit

1.121

Quoted Energy charge per unit

Rs./unit

1.190

Total Fuel Cost

Rs. Cr.

655

Transmission Cost

Rs. Cr.

179

Capacity cost per unit

Rs./unit

1.544

Energy cost per unit

Rs./unit

2.415

Transmission Cost per unit

Rs./unit

0.661

Under-recovery (capacity)

Rs. Cr.

115

Under recovery (energy)

Rs. Cr.

511

Source: Statutory Auditor Certificate.”

* adjusted for discount for prompt payment, other operating income, etc.

(Source: As cited in Committee Report to CERC for determination of compensatory tariff in the matter of Adani Power Limited, August 2013)

Exhibit 5: Results of Case I bids based Tariffs cited by Committee

Bid type

State

Bidder

MW

Fuel Type

Levelised

Tariff (Rs/kWh)

Period

Medium Term

Tamil Nadu

JPL

200

Captive Coal block

4.91

1st Mar 2012 – 30th Sept 2017

AEL

200

Blended

4.99

OPG

70

Imported

5.99

Medium Term

Bihar

AEL

200

Blended Coal

4.41

1st Mar 2012 – 30th Sept 2017

Sterlite

100

Domestic Coal

4.95

JPL

200

Captive Coal Block

5.16

Medium Term

Kerala

PTC India- Balco

100

Domestic Coal

4.506

Mar'14 – Mar'17

NVVN

300

Domestic Coal

4.526

Jindal Power Ltd.

300

Captive Coal Block

4 .543

Tata Power Trading

70

Domestic Coal

4.61

KSK Mahanadi Power

Company Ltd.

200

Domestic Coal

5

KSK Wardha Power

120

Domestic Coal

5.356

Global Energy Pvt. Ltd.

25

Domestic Coal

5.892

Coastal Energen

150

Imported

6.041

JSW Power Trading

100

Imported

6.477

JSW Power Trading

200

Imported

6.815

Long Term

AP

GMR

200

Domestic Coal

4.62

1st Oct 2012 – 31st Dec 2019

Abhijeet

50

Domestic Coal

4.974

Balco

100

Domestic Coal

5.175

Long Term

UP

NSL-Odisha

300

Domestic Coal

4.48

25 years

PTC (TRN/ACB)

390

Domestic Coal

4.886

25 years

Lanco Babandh

423.9

Domestic Coal

5.074

25 years

RKM Powergen

350

Domestic Coal

5.088

25 years

KSK Chhattisgarh

1000

Domestic Coal

5.443

25 years

PTC Moserbaer

361

Domestic Coal

5.73

25 years

Navyug-Krishnapatnam

800

Imported Coal

5.843

25 years

Indiabulls-Nasik

1200

Domestic Coal

5.97

25 years

Long Term

UP

PTC-DB Chhattisgarh

203

Domestic Coal

5.97

25 years

Jindal

300

Captive Coal Block

6.115

25 years

Indiabulls-Amravati

600

Domestic Coo I

6.3

25 years

Lanco-Amarkantak

1072.5

Domestic Coal

6.303

25 years

NCC

200

Blended Coal

6.425

25 years

Lanco-Vidarbha

454.2

Domestic Coal

6.643

25 years

PTC (East Coast)

300

Blended

6.819

25 years

PTC (DB Power MP)

302

Domestic Coal

7.101

25 years

Long Term

Rajasthan

LBPL

100

Domestic Coal

4.943

25 years

Athena Chhattisgarh Power

Ltd

200

Domestic Coal

5.143

25 years

SKS Power Generation

Chhattisgarh Ltd

100

Domestic Coal

5.3

25 years

LVTPL

100

Domestic Coal

5.49

25 years

Anuppur Thermal Power Project

200

Domestic Coal

5.517

25 years

KSK Mahanadi Power Project (Chhattisgarh)

475

Domestic Coal

5.572

25 years

Jindal Power Limited

300

Captive Coal Block

6.038

25 years

LAPL

100

Domestic Coal

7.11

25 years

(Source: As cited in Committee Report to CERC for determination of compensatory tariff in the matter of Adani Power Limited, August 2013)

Exhibit 6: APL and other Bidders’ Quotes for Capacity Charge for Haryana Bid

Company

Capacity charge (Rs./unit)

Adani Power

0.977

Lanco

1.284

PTC – GMR

1.346

Essar

2.121

Reliance Rosa

1.306

Reliance Chitrangi

1.170

Tata Power

1.547

Electrosteel

2.785

(Source: Committee Report to CERC for determination of compensatory tariff in the matter of Adani Power Limited, August 2013)

Exhibit 7: Technical Parameters used to Assess Alternative Mechanisms

  • Station heat rate: 2354 kcal/kWh and auxiliary consumption of 6.5% (Technical parameters as per Technical Consultant Report). In the GERC order number 1210/2012 dated 7 January 2013, the station heat rate was considered as 2150 kcal/kWh. However, as per the Technical Consultant’s report, based upon prevailing site conditions and technical parameters, the achievable station heat rate, is 2354 kcal/kWh. The SHR as per CERC norm is 2380 kcal/kWh. The Technical Consultant has hence recommended SHR of 2354 kcal/kWh. The detailed calculation is mentioned in chapter 8 of the Report.
  • HBA index calculated as on 30 June 2013 for 6322 kcal/kg coal at USD 78.76.
  • Forex rate applied is Rs. 59.70/USD.
  • Discount of 9% considered for duly adjusted lower GCV coal
  • Ocean freight has been assumed at USD 12/ton
  • Insurance and Transactional charges assumed @ 3%

Source: Committee Report to CERC for determination of compensatory tariff in the matter of Adani Power Limited, August 2013

Exhibit 8: Recommendations on Determination of Actual Energy Cost for Gujarat PPA

Principles:

Particulars

Gujarat PPA

A

Cost of Coal (Rs. Cr. for the year) corresponding to the Energy Supplied under the PPA

To be computed at Plant Bus bar using the cost of imported coal (based on details of actual cost incurred during the year) and other operating parameters as discussed below #

B

Transmission Charges

(Rs. Cr. for the year)

Not Applicable, since delivery point is plant bus bar

C

Total Revised Energy Charges

(Rs. Cr for the year)

Sum of the above i.e. (A) + (B)

D

Less: Profit from Indonesian coal mining operations

Actual Profit from coal mining operation in Indonesia (as per audited figures) in proportion to the revenues from coal used for energy supplied under PPA in Phase III to total revenues, duly adjusted with applicable tax structure up to Indonesia (if profits are retained in Indonesia) and applicable tax structure up to India (if profits are remitted to India) (Rs. Cr.); (As per principles set out in the formulae agreed with and computations performed by KPMG)

E

Less: Profit from sale of power beyond Normative Availability on merchant basis (If any)

The actual excess realization from sale on merchant basis, net of all related expenses, over total generation cost to be shared

F

Net Actual Cost towards Energy Charges

(C)-(D)-(E)

Recommendations on Energy Charge:

Particulars

Gujarat PPA

Present CERC norms

Station Heat Rate

2354 kcal/kWh (as assessed by Tech Consultant i.e. Design SHR plus maximum site conditions allowance@ 6.5%) or applicable CERC norms or actual, whichever is lowest

2380 kcal/kWh

Auxiliary Consumption

Design of 7.05% (as assessed by Tech Consultant) or applicable CERC norms, whichever is lower.

6.5%.

Transmission losses

Not Applicable (Since PPA off-take is at Bus bar)

GCV of Coal

As Certified by Third Party Sampling Agency of Repute based on sampling at Plant

Blending Ratio of Low Grade Coal

Bunyu or any other low grade coal will be in such a proportion that GCV(ARB) of blended coal is within the range of ± 5% of design CV of 4500 kcal/kg

Low Grade coal will be used maximum, to the extent available, keeping the GCV of Blended cool not less than 4500 kcal/kg

Landed Cost of Fuel

Imported Coal

Remark

FOB prices of Imported Coal#

As per Actual or benchmarked with HBA index or any other relevant indices

In case of change in pricing framework in Indonesia or change in source of coal to other country, relevant coal indices will be used.

Ocean Freight#

Actual as incurred by the Company on the basis of Contracts.

Capped to freight index or guidance suggested by CERC

Transaction L/C and Insurance Charges

Actual as incurred by the Company

This will include cost in regard to LC, Bank and financial charges, insurance and other transaction costs

Port handling Charges at Mundra

As per Port Service Agreement with APSEZ less agreed discount

The Discount of Rs. 20 per MT to be continued

Transit & Handling Losses

Actual or CERC norms, whichever is lower

# Cost of Imported coal (FOB and Ocean freight) should not Increase beyond HBA benchmark + actual transportation cost from Indonesia

(Source: Committee Report to CERC for determination of compensatory tariff in the matter of Adani Power Limited, August 2013)

Exhibit 9: Recommendations on Determination of Actual Energy Cost for Haryana PPA

Principles:

Particular

Haryana PPA

A

Cost of Coal (Rs. Cr. for the year) corresponding to the Energy Supplied under the PPA.

To be computed at Plant Bus bar using the cost of imported coal and domestic coal (based on details of actual cost incurred during the year) and other operating parameters as discussed below#

B

Transmission Charges

(Rs. Cr. for the year)

On actual cost plus basis for use of HVDC system * , till transmission license is granted

Once transmission license is granted, paid as per CERC norms

C

Total Revised Energy Charges

(Rs. Cr. For the year)

Sum of the above i.e. (A) + (B)

D

Less: Profit from Indonesian coal mining operations

Actual Profit from coal mining operation in Indonesia (as per audited figures) in proportion to the revenues from coal used for energy supplied under PPA (if any) in Phase IV to total revenues, duly adjusted with applicable tax structure up to Indonesia (if profits are retained in Indonesia) and applicable tax structure up to India (if profits are remitted to India) (Rs. Cr.)

E

Less: Profit from sale of power beyond Normative Availability on merchant basis (If any)

The actual excess realization from sale on merchant basis, net of all related expenses, over total generation cost to be shared

F

Net Actual Cost towards Energy Charges

(C)–(D)–(E)

* HVDC system will include 500 KV Mundra Mohindergarh line along with associated HVDC terminal, substations & Electrode line, 400 KV Mohindergarh-Dhanonda line & 400 KV Mohindergarh-Bhiwani line (if used)

#In case optimization of coal linkage/swapping, is allowed by Goi/CIL, APL will continue to claim energy charges on notional usage of domestic coal at Mundra for the actual quantum supplied against linkage i.e. the mechanism to determine Actual cost toward Energy Charges will be continued without any change, taking into account landed cost of domestic coal for Mundra Project as if domestic coal is being used at Mundra. Any financial advantage on account of Optimization of coal linkage/swapping will be allowed to be retained with APL to adjust against under recovery of Capacity Charge.

Recommendations on Energy Charge:

Particulars

Haryana PPA

Present CERC norms

Station Heat Rate

2354 kcal/kWh (as assessed by Tech Consultant i.e. Design SHR plus the maximum site conditions allowance @6.5%) or applicable CERC norms or actual, whichever is lowest.

2380 kcal/kWh

Auxiliary Consumption

Design of 8.97% (Plant Aux of 7.05% and FGD Aux of 1.92%) (As assessed by Technical Consultant) or applicable

CERC norms for plant Aux plus Design

Aux of FGD, whichever is lower.

6.5%. For FGD, there are no norms at present.

Transmission Losses

On actual, or as per CERC norms whichever is lower

Losses as per CERC norms after Transmission license is granted

GCV of Coal

As Certified by Third Party Sampling

Agency of Repute based on sampling

at Plant

Blending Ratio of Low Grade Coal

Domestic coal or any other low grade coal will be used in such a proportion that GCV (ARB) of blended cool is in the range of ±5% design CV of 4500 kcal/kg

Low Grade coal will be used maximum, to the extent available, keeping the GCV of Blended cool not less than 4500 kcal/kg

Landed Cost of fuel- Imported and Domestic Coal

IMPORTED COAL

Imported Coal

Remark

FOB prices of Imported Coal#

As per Actual or benchmarked with HBA index or any other relevant indices

In case of change in pricing framework in Indonesia or change in source of cool to other country, relevant coal indices will be used.

Ocean Freight#

Actual as incurred by the Company on the basis of Contracts.

Capped to freight index or guidance suggested by CERC

Transaction L/c and Insurance Charges

Actual as incurred by the Company

This will include LC, Bank and financial charges and other transaction costs

Port handling Charges at Mundra

As per Port Service Agreement with APSEZ less agreed discount

The Discount of Rs. 20 per MT to be continued

Transit & Handling Losses

Actual or CERC norms,

whichever is lower

DOMESTIC COAL

Imported Coal

Remark

MCL ex-mine coal cost

As notified by CIL from time to time (including applicable taxes and duties)

To be used on notional basis, if coal linkage optimization is taken by the Company

Transportation from MCL to Mundra

Contracted price being actually incurred by APL subject to ceiling of railway freight

Capped to railway freight from MCL to Mundra

Transaction L/c and Insurance Charges

Actual as incurred by the Company

This will include LC, Bank and financial charges and other transaction costs

Port handling Charges at Mundra

As per Port Service Agreement with APSEZ less agreed discount

The discount of Rs. 20 per MT to be continued

Transit & Handling Losses

Actual or CERC norms,

whichever is lower

#Cost of imported coal (FOB and Ocean freight) should not increase beyond HBA benchmark + actual transportation cost from Indonesia

(Source: Committee Report to CERC for determination of compensatory tariff in the matter of Adani Power Limited, August 2013)

Notes

1. This exhibit is taken entirely from the case Adani Power Limited (A) of IIM Ahmedabad.

2. This exhibit is taken entirely from the case Adani Power Limited (A) of IIM Ahmedabad.

3. Amended on 30.3.2006, 18.8.2006, and 27.9.2007.

4. Guidelines for Determination of Tariff by Bidding Process for Procurement of Power by Distribution Licensees dated 19 January 2005, Ministry of Power, Government of India.

This case was prepared for inclusion in Sage Business Cases primarily as a basis for classroom discussion or self-study, and is not meant to illustrate either effective or ineffective management styles. Nothing herein shall be deemed to be an endorsement of any kind. This case is for scholarly, educational, or personal use only within your university, and cannot be forwarded outside the university or used for other commercial purposes.

2024 Sage Publications, Inc. All Rights Reserved

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