Indian Power Sector

Indian Power Sector – Emerging Challenges to Growth With a critical mass of progress in regulatory reforms and soaring economic growth, the Indian power sector is now primed for take off. Over the next ten years, the sector will need US$200 bn in new investments. How India deals with the remaining challenges of the restructuring process and emerging fuel shortages will dictate what happens in the years to come. By SANDEEP KUMAR, ANURAG KHETAN & BISHAL THAPA .

I

ndia received the perfect Valentine’s Day present this year. The Sensex, India’s key stock market index, which had been on a bull run since November last year, finally peaked at 6,700, up almost 50% from the low of May last year. If the news was received with subdued euphoria, it was only because announcements about growth have become just too commonplace. Of the 650 companies that had announced quarterly profits by December, over 150 had posted profit growth of over 200%. Fuelled by foreign inflows and expectations of yet another miracle budget, the run up to the Valentine’s Day Sensex was indication that the love affair between foreign investors and India Inc. may be over the first date jitters. But the courtship isn’t quite ready to turn into a full fledged wedding proposal yet. The key worry for investors is whether India can sustain the 6-7% economic growth rate. An ailing infrastructure network that needs massive reinforcement and expansion remains one of the largest obstacles to such growth. Progress in the Indian power sector, with current electricity shortages of over 11% of peak and 7% of energy, will be one of the key determinants to future growth. All this is not breaking news; the Indian government has long been aware of the need to transform the power sector. Throughout the nineties it worked steadily to liberalise the sector and initiated reforms that culminated in the Electricity Act 2003. And thus far, the momentum on power sector reforms has survived Governments of both left and right. India has set itself an ambitious target of more than doubling per-capita electricity consumption by FY 2011 and the Ministry of Power projects an

investment need of 9,000 bn Indian Rupees (INR), or US$ 200 billion to make it possible 1. The investment plan aims to expand the power infrastructure base for economic growth while making electricity accessible to all. Nobody is quite betting on its success just yet but it is clear that Government and policymakers are taking the problems of the sector seriously. Transforming the state-led bureaucratic Indian power sector into a competitive market attractive to private investors was never going to be easy. But economic liberalisation of the nineties along with the pressures from the country’s economic

India has set itself an ambitious target of more than doubling per-capita electricity consumption by 2011 growth has forced open the sector. Previous reform efforts etched slowly into industry’s regulatory structure, ownership, investment, and management practices. Political will has gradually coalesced through the reform process of the nineties and the Electricity Act 2003 is now galvanising change. With the implementation of the Electricity Act, progress on structural and regulatory reforms has achieved enough critical mass to become irreversible. The change has sparked renewed interest in private investment opportunities. What happens next in the sector will now depend critically on two things:

TABLE 1. INDIA’S POWER SECTOR PLANS – THE US$ 200 BILLION PACKAGE Planned Enhancements FY 2004 FY 2011 Generation Capacity (thousand MW)

207

9,000 326

30,000 386

Distribution & Rural Electrification Households with access (%) Peak Deficit (%) Energy Deficit (%)

60% 11% 7%

100% 0% 0%

Renovation & Modernisation Electricity consumption per capita (kwh)

326

819

Source: Planning Commission (Xth Plan) and Ministry of Power

1

115

Transmission Interstate Transmission Capacity (MW) Transmission (‘000 ctk Kms)


Reprinted from WorldPPower 2005

Estimated Cost FY 04 - FY 11 (bn) INR USD 5,532

123

1,265

28

1,949

43

250

6

(1) How India overcomes the remaining elements of restructuring that seek to sever the last few vestiges of political influence. (2) How India deals with the emerging challenges of fuel shortages that threaten to derail power capacity expansion plans. The remainder of this article discusses the two identified challenges to growth in the Indian power sector.

REFORM CHALLENGES The Indian power sector, long considered a symbol of the nation’s state led economic development, has been plagued by bureaucratic inefficiency and political interference for decades. Vertically integrated state utilities (State Electricity Boards (SEB)) are practically insolvent with commercial losses estimated at INR 225 bn (US$ 5 bn) for FY 2004 alone 2. The tariff structure is differentiated by consumer category with a cross subsidy charge that penalises commercial and industrial users at the expense of the more politically influential agricultural sector. Transmission and distribution losses remain high – almost 40% – and power theft is endemic and tolerated. The Electricity Act 2003 struck at the core of these issues. Replacing the disparate reforms of the 1990s, the Electricity Act 2003 brought together structural and regulatory reforms designed to foster competitive markets, encourage private participation and transform the state’s role from service provider to regulator. The Act directs the unbundling of vertically integrated utilities and creates autonomous state electricity regulatory commissions. Electricity trading has been recognised as a separate line of business and regulatory commissions have been directed to develop rules on open access, rationalise tariffs to progressively reflect cost of supply, reduce cross subsidies, institute strong anti-theft provisions and protect consumer interest. In India’s constitution, electricity is a shared responsibility between the centre and states. Though overall progress at the state level is mixed, almost all the states have initiated some structural and regulatory reforms. About 22 of the 29 states have established electricity regulatory commissions empowered to regulate tariffs and establish performance codes. About half the

India

FIGURE 1. INDIA’S POWER SYSTEM AT A GLANCE – INSTALLED CAPACITY (115,476 MW) INSTALLED CAPACITY, JANUARY 2005 (MW) 10%

2% 3% Coal 59% Hydro 26% Gas 10% Nuclear 2% Others 3%

59% 26%

INSTALLED CAPACITY BY OWNERSHIP 11% 33%

56%

Central 33%

State 56%

Private 11%

Source: Ministry of Power & ICF Consulting Research

states have unbundled the vertically integrated state electricity boards. Some form of unbundling across all the states is expected by the target date of June 2005. Despite the variation on progress, it is clear that the basic thrust of the Electricity Act has percolated down to the states. A critical mass of reform initiatives has developed and implementation hurdles now relate mainly to difficulties of the restructuring process. While the centre-led Electricity Act laid out the vision for a deregulated power sector, states have the charge of implementing the restructuring process. There is as yet no clear road map for the restructuring process and the Electricity Act leaves it to the states to decide. Delhi and Orissa, the states at the most advanced stages of restructuring, pursued two different models and provide the only real life experiences. The road to competitive power markets in India, particularly one with active private participation, will depend on how the restructuring process deals with three key issues: 1) Payment risk from sale of electricity 2) Tariff rationalisation 3) Open access

PAYMENT RISK

One of the biggest worries for private generators is that they may never get paid for the electricity they produce. Most distribution companies are still under state control, either directly through the SEB or their unbundled successors, and are financially distressed. Commercial losses at SEB in 2004-05 alone are estimated to be INR 225 bn (US$ 5 bn)5. Average sales revenue to cost ratio remains well under 70%. Much of these losses result from the underlying tariff structure and low revenue collection rates. The tariff structure is defined by consumer class and a cross subsidy structure is used to subsidise domestic and agricultural users. The higher rates paid by industrial consumers are insufficient to cover the subsidies provided. In addition, revenue arrears, or collection inefficiencies, on average are about 25 – 30%. In some states like Bihar and Jammu and Kashmir, revenue arrears are astoundingly high – as much as 155% and 227% respectively. In a recent rating of SEBs conducted by the Ministry of Power, the median score for financing risk was well short of 10 against a maximum of 23. Only ten states achieved a score greater than 10. While investors may be lured into power Key Features of the Electricity Act projects with promises * Unbundled vertically integrated state utilities of long-term * Established independent electricity regulatory commission agreements, the ability Generation No license required for establishing of SEBs to pay for the non-hydel plants purchase of electricity Distributed generation and generation from renewables encouraged still remains Transmission Non-discriminatory open access to transmission system questionable. Simple Introduction of power trading as a separate line of business unbundling followed by Independent power transmission companies allowed privatisation or Unbundling of transmission and trading corporatisation may not Distribution Right to choose supplier be sufficient. The Rationalisation of tariff restructuring process Progressive reduction of cross subsidies must determine who Metered supply of electricity and strong anti-theft provisions absorbs the existing

liabilities and re-establish the financial credibility of electricity purchasing entities.

TARIFF

RATIONALISATION

Subsidies to agricultural and household consumers coupled with very high levels of T&D losses have long kept tariffs out of sync with costs. Seeking to bring revenues in line with the cost of supply, the Electricity Act required the independent regulatory commissions to rationalise tariffs. Most states have followed the guideline with vigour. Through the tariff orders, a number of

Most distribution companies are still under state control ... and are financially distressed commissions have instituted measures to allocate revenue requirement in an economically efficient manner by reducing the extent of cross subsidies. Though these new tariff orders are steps in the right direction, bringing them in line with supply costs will ultimately involve raising prices for the vast majority of consumers, particularly in the agricultural sector, that have been used to decades of subsidised power. The planning commission estimated that for SEBs to post a rate of return of 3% in FY 2001, average tariffs would have to be increased by approximately 50% (or INR 1.17 /kWh)6 that year. Such increases challenge the fundamental nexus between politicians and consumers. Tariff rationalisation will be more than an exercise in bringing revenues at par with cost and will require significant political capital to be spent in convincing agricultural users to accept higher prices. Thus far, the politicians have yet to wager their bets. Reprinted from WorldPPower 2005


2

India

Competing Models for Restructuring The Orissa Model

The Delhi Model

Orissa was the first state to embark on the reform programme after the state Electricity Reform Act became effective in April 1996.

The Delhi Electricity Reform Act comes into force in March 2001.

Almost immediately, the Orissa State Electricity Board is partially unbundled into three separate entities: Orissa Hydro Power Corporation (OHPC – for hydro generation), Orissa Power Generation Corporation (OPGC – for thermal generation) and Grid Corporation of Orissa (GRIDCO – for transmission and distribution).

Two months later, Delhi Vidyut Board (DVB, the state’s electricity board) establishes six shell companies (holding company, generating company, transmission company, three distribution companies) to be operationalised on transfer.

Generation is first privatised. In June 1998, AES purchases 49% stake in OPGC. In the second phase, the distribution assets, properties and personnel of GRIDCO is broken into four distribution companies. BSES purchases three of them (NESCO, WESCO and SOUTHCO) in April 1999 and one (CESCO) is transferred to AES Transpower (joint venture of AES and Jyothi Structures Ltd) in September 1999.

Distribution is first privatised. 51% of the equity in three distribution companies are sold to two privately owned Indian power companies, BSES and Tata Power. DVB ceases to exist and is replaced by the holding company, the generation company and transmission company. Delhi government retains ownership of the holding, generation and transmission company.

GRIDCO retains most of the past liabilities of distribution companies in order to conclude sale. Its cash deficit soars almost 40% between 1998-1999 and 1999-20003, and the company has difficulty covering operating expenses.

Holding company retains all unserviceable liabilities. Asset values of successor companies are pegged to serviceable liabilities. Existing serviceable DVB liabilities will be paid by successor agency after a four year grace period.

Private investors bid for distribution companies based on assumptions contained in the information memorandum. Assets of distribution companies may have been over-valued because of underestimated losses (estimated at 35%, actually more than 50%; the 100% collection efficiency estimated is actually 83%) 4. Bidders assumed that future tariff adjustments would balance any initial over-valuation. No transitional support to private distribution companies planned and turn-around expected in 2/3 years.

Introduced concept of aggregate technical and commercial (AT&C) losses, rather than transmission and distribution (T&D) losses. Private investors bid for distribution companies on the basis of a five year AT&C targets, indicative multi-year tariff profile and projected Government assistance. A five year transitional period with some Government support over the period.

OPEN ACCESS The Electricity Act recognised open access as one of the most important instruments for transforming the power sector. The Act afforded consumers the ability to directly source their electricity from suppliers using existing networks and recognised trading as a separate line of business. A number of central and state level regulatory initiatives have sought to develop and strengthen open access rules7. These rules could well be the panacea for much of India’s electricity woes. By challenging the sole-purchasing power of the state electricity board (or their successors), generators have an opportunity to reduce the payment risk, avoid the hazards of commercial losses from theft and provide industrial users the incentive to seek out more cost-efficient supply sources. Despite the obvious progress on open access rules, the benefits of it are yet to be realised. The effectiveness of open access has been stymied by provision of a ‘surcharge’ that is currently levied on open-access customers belonging to any category contributing towards the cross 3


Reprinted from WorldPPower 2005

THE RACE

FOR

FUELS

While India’s reforms have attained enough critical mass and are slowly winding their way through the states, a more immediate concern on fuel shortages threatens to derail short-term growth prospects in the power sector. At the end of February, 24 plants (23,000 MW, 35% of total coal capacity) had coal stock of less than 7 days out of which about 8,000 MW had stock of less than 4 days8. The failure to activate fuel supplies has threatened the operation of some plants and postponed the building of several others. In January, NTPC had to begin seeking alternate fuel supply options because the mines supporting its new pit head plants (Talcher –II and Rihand-II, total 2,000 MW) had yet to receive clearance9. Of the 4,300 MW planned capacity additions off-track in the Xth Plan, almost 65% had slipped for fuel supply reasons10. The 100,000 MW of capacity additions needed through FY 2011 is unlikely to materialise unless India can find the fuel supply sources and distribution networks to support the projected growth. COAL MARKETS

subsidy. Though the Electricity Act may have given SERCs the authority to levy a surcharge to support subsidy financing, its implementation has merely helped protect incumbency rights and reduce the pace of restructuring. The vision of competitive markets with open access is

India’s coal demand is expected to grow 7% annually over the next decade unlikely to be fully realised without further clarity on ‘surcharge’. Though India’s power sector reforms are not yet free of difficulty, the ongoing restructuring efforts illustrates that a critical mass of reforms have been achieved. The process now appears irreversible. The pace and eventual outcome of reforms, however, will be dictated by the willingness of politicians and policymakers to sever the remaining political ties with the sector.

India’s coal demand is expected to grow 7% annually over the next decade11. Much of this increased demand will come from power generation, which currently accounts for about 80% of total coal consumption. For a country that has relied heavily on domestic coal, the stresses of such a demand growth are already apparent. Over the last decade, coal imports have steadily risen at an annual rate of 12%12. Coal consumers, both in the power and industrial sectors, have increasingly begun to look for sourcing options from abroad. Jindal Stainless and Tata Steel were reported to be looking to acquire coal mines in Indonesia, Australia and New Zealand to support the expansion of their power and steel ventures in India 13. Proven coal reserves in India are estimated to be 94 billion tonnes and at current production levels, enough for the next 230 years. But current production levels are simply not enough to meet the growing demand. Imported coal, though an option, does not provide the same cost benefits of domestic coal (especially for pit-head plants where most new coal plants are likely to be located) but could fundamentally alter the

India

FIGURE 3. COSTS OF SUPPLIES & TARIFFS 400

Paise (kwh)

300

0

FY 96

FY 97

FY 98

Average Tariff FY 99

FY 00

FY 01

Source: Annual report on the working of State Electricity Boards & Electricity Departments, Planning Commission 2002

FIGURE 4. COAL DEMAND & SUPPLY

800

Millions of Tonnes

Projection Coal Demand Domestic Production

600

400

FY 10

FY 08

FY 06

FY 04

FY 02

FY 00

FY 98

FY 96

FY 94

FY 92

0

FY 90

200

Source: International Energy Association, 2002 and Planning Commission (Xth Plan)

and the National Commodity and Derivatives Exchange Limited. A petroleum and natural gas regulatory board has been proposed along with a draft pipeline policy seeking to unbundle gas transportation from supply and establish ‘contract carrier’ norms for access. Expanding gas supply sources and distribution infrastructure is now the key to further evolution of gas markets in India, and visible signs of progress in tackling the infrastructure bottlenecks

are already evident. Imports of natural gas started in 2004 after the commissioning of Petronet’s Dahej LNG terminal. At least 2 more LNG terminals are expected to come online by 2009 and the Dabhol LNG terminal is also gearing up for operations. Proposed plans for LNG terminals could add over 80 million standard cubic metres per day (MMSCMD) of gas capacity. Gas-import pipelines from Iran and Myanmar are also under serious consideration. Domestic gas exploration has

FIGURE 5. GAS SUPPLY & DEMAND 100 Projection Reliance Gas 80 Supply

Demand

60

40

20

FY 10

FY 08

FY 06

FY 04

FY 02

FY 00

FY 98

FY 96

FY 94

LNG Imports Begin 0

FY 92

Gas has emerged as the new frontier for energy supply in India and as a new industry relatively free of bureaucratic red tape, holds the hopes for supporting the expansion in the power sector. Gas demand in India is expected to increase sharply at an annual average growth rate of about 8.5% through FY 2011. Increased demand comes not only from the power sector, which currently accounts for about 40% of gas consumption, but also from the industrial and fertiliser sectors. Current supply options, however, are extremely limited. Baseline projections, including LNG imports and Reliance Gas from the KG basin, indicate a supply shortage of about 15-20 billion cubic metres (bcm) annually by FY 2011. Gas markets in India have matured considerably since the sector was first opened in the mid nineties. The New Exploration and Licensing Policy (NELP) was launched to attract private capital in exploration activity and has been successful in drawing both domestic and international participants. Several key discoveries have been made under the NELP, though much of the sedimentary basins of the country remains untested. Downstream gas marketing has also been liberalised. An online spot trading facility for gas contracts is jointly being developed by Gail Ltd

Average Cost of supplies

FY 90

GAS MARKETS

100

BCM

imported coal-gas choice dynamics for new plants. Against this backdrop, some reforms have been initiated in the coal industry but hardly with the zeal of a sector so urgently in need of change. Between 1996 and 2000, after several decades of control, coal prices were deregulated along with the distribution to industries other than power and steel. Captive mining by private sector engaged in iron and steel and power generation have also been allowed. Although FDI limits for captive mining for power plants have been removed and those for iron and steel have been increased to 74%, private companies are still restricted only to captive coal mining. It is unlikely that the state-owned coal companies that have long held a monopoly over coal markets in India can alone bring the investment and efficiency improvements in the sector14. Without some major reforms or restructuring that unlocks the constraints in coal supply, India’s vast potential for growth in coal capacity additions may remain just that – a great potential.

200

Source: Prime Minister’s Office (Hydrocarbon Vision, 2025) and Planning Commission (Xth Plan)

Reprinted from WorldPPower 2005


4

India

TABLE 2. LNG TERMINALS Capacity MMSCMD

Supply Source

Dahej *

20

Ras Gas (Qatar)

Hazira **

10

Various

Kochi

10

Ras Gas (Qatar)

GAIL, ONGC IOC, BPCL

GDF, ADB

Dabhol ***

20

Oman

MSEB

GE, Bechel

Enmore

10

Qatar

Grasim

Unocal, CMS Energy, Woodside Energy, Siemens Project Ventures

Kakinada (Krishnapatnam)

10

Various

IOC, Coconada Port

BP, Petronas, ISP

Gopalpur

20

Australia

Orissa State, VOGL

AMIG, Australia LNG

Pipavav LNG

10

Yemen

Trimbay

12

ME/SEA

TPC, GAIL

TGPI

LNG Terminals

Partners Indian GAIL, ONGC IOC, BPCL

Foreign

Footnotes GDF, ADB Royal Dutch Shell,Total

BG

Notes: * Operational ** Under Construction ** Undergoing a revival

expanded considerably with NELP. 164 blocks have been awarded, of which 20 have announced some finds. A national gas pipeline grid connecting over 8,000 kms and able to transport about 100 MMSCMD is also being proposed. While gas may hold the promise of unlocking growth in the power sector, the outcome will depend on the willingness of private investors and Government to make the initial investment in supply infrastructure.

CONCLUSIONS Despite the potential offered by the India’s power sector, investors have long been weary of the sector’s bureaucracy and regulatory complexity. Now with a critical mass of progress in reforms, private investors have been quick to pick 5


Reprinted from WorldPPower 2005

and expanding capacity at its plant in the state; Reliance Energy announced plans for additions of 3,000 MW of gas-fired capacity in UP. The US$ 200 billion investment bill may not be the primary constraint in transforming the Indian power sector. Instead the emerging challenges to growth relate to the remaining issues of regulatory reform and fuel supplies. While progress on reforms now appear irreversible, political will on resolving the remaining regulatory issues still remain unclear. Furthermore, fuel shortage resulting from limited supply options and transportation infrastructure threaten to derail power capacity expansion plans. How India tackles these obstacles remains to be seen. But if the aggressive vision of Indian planners is to be believed, it may not be long before the courtship of foreign investors and India Inc. does indeed blossom into a full fledged wedding proposal  1. Planning Commission (Xth Plan) and Ministry of Power. 2. Indian Budget 2005-06. 3. “Orissa Power Sector Reform: A Brief Overview of the Process,” Infrastructure Development Finance Company Ltd. (IDFC Ltd.), February 2000. 4. Ibid, IDFC Ltd. 5. Indian Budget 2005-06. 6. “Annual Report on the Workings of State Electricity Boards and Electricity Departments,” Planning Commission, May 2002. 7. Open access regulations rules relating to transmission customer class definition and pricing, were approved by CERC in January 2004 and amended in September 2004 and January 2005. CERC also approved trading related regulations in January 2004. Several states, including Rajasthan, Maharastra, Tamil Nadu, Andra Pradesh, Gujrat, Karnataka, Madhya Pradesh, Orissa and Uttrananchal have approved or developed draft open access rules with time-bound implementation guidelines. 8. Central Electricity Authority, MoP, GoI. http://www.cea.nic.in/data/opt2_daily_coal.htm.

on the opportunities. Just last month Brakel Corporation of Holland expressed interest in investing US$ 1 bn on hydel projects in Himal

9. “NTPC coal imports may give consumers a power shock,” The Economic Times, 27 January 2005. 10. National Electricity Plan, 2005. Central Electricity Authority. 11. Planning Commission Xth Plan.

... the emerging challenges to growth relate to the remaining issues of regulatory reform and fuel supplies Pradesh. More recently, Alstom picked up a 25% stake in Torrent Power; AES has expressed interest in re-acquiring the distribution company in Orissa

12. International Energy Association, 2002. 13. “Tata Steel scouts for coal mines in Australia, NZ,” Business Standard, 26 January 2005. “Jindals eyeing coal mine in Indonesia,” The Economic Times, 28 January 2005. 14. Coal India Limited and its subsidiaries effectively control about 90% of domestic coal production and distribution.

Sandeep Kumar, Anurag Khetan and Bishal Thapa are with the New Delhi office of ICF Consulting. The authors wish to acknowledge support of Shanthi Muthiah (ICF Washington DC office) and Harriet Hoexter (ICF London office). www.icfconsulting.com