Malaysiakini Letter

Power market - TNB must move towards liberalisation

JT
Published:  |  Modified:

Tenaga Nasional Berhad - the national electricity company – is the dominant electric utility in Malaysia. It owns approximately 60% of all Peninsular Malaysia’s generation assets and approximately 55% of all Malaysian generation. TNB holds a monopoly of transmission and distribution in Peninsular Malaysia.

In Sarawak and Sabah, the Sarawak Electricity Supply Corporation and Sabah Electricity Sdn Bhd (TNB’s subsidiary) supply power to consumers. Energy policy is overseen by the Economic Planning Unit in the Prime Minister’s Department. The industry regulator is the Energy Commission, which reports to the energy, water and communications ministry.

Its primary role is to implement the Electricity Supply Act 1990 (amended 2001) tariff-setting and regulating the electricity supply and piped gas supply industries in Peninsular Malaysia and Sabah.

Up to 1992, power generation, transmission and distribution in Peninsular Malaysia were provided largely by TNB. With the government’s adoption of the privatisation policy in the late 1980s, TNB was listed on the local bourse on Feb 29, 1992.

Although TNB was privatised (the government and its agencies holds about 60% of the equity) as a vertically-integrated power utility, the government decided to introduce competition in the power generation sector for the following plausible reasons :

• there was a major power black-out (over 16 hours) throughout Peninsular Malaysia towards end of 1992;

• in many developed economies, competition was introduced after state privatisation;

• equity markets seem to welcome power utilities – which encouraged entrepreneurs to propose unsolicited bids.

• Malaysia’s economic expansion in the early 1990s required a surging need for power.

With the above background, the government was in receipt of unsolicited proposals from independent power producers (‘IPPs’).

The first five IPPs with Power Purchase Agreements (‘PPAs’) signed (1993-94) were as follows:

• YTL Power Generation (‘YTL’) (1,212MW) with power plants in Paka, Terengganu and Pasir Gudang, Johor;

• Segari Energy Ventures (‘Segari’) (1,303MW) in Lumut, Perak;

• Genting Sanyen Power (‘Genting’) (762MW) in Kuala Langat, Selangor;

• Port Dickson Power (‘PD Power’) (440MW) in Port Dickson, Negeri Sembilan; and

• Powertek (‘Powertek’) (440MW) in Malacca.

Total new generation capacity of 4,157MW was in place by 1996. YTL, Segari and Genting are combined-cycle gas turbine (‘CCGT’) base-load plants while PD Power and Powertek are peaking plants (open-cycle gas turbine).

On a peak demand of 13,887 MW recorded in May 2008, the reserve margin was at 42%. Assuming an average 5% growth in peak demand, the reserve margin should range between 27% to 40% for next few years. It will increase to 47% in August 2009 with the full commissioning of Jimah Power plants – meaning installed capacity is boosted by 12.2%.

With a steady drop in reserve margin from 1995 to 2000, new capacity was planted-up post – 2000. The new IPPs and capacities are as follows:-

Prai Power (350MW), Panglima Power (720), Teknologi Tenaga Perlis Consortium (650),

GB3 (640), Pahlawan Power (330), Tg Bin Power (2,100) and Jimah Energy Ventures (1,400).

Of the above plant-ups, Malakoff Berhad and Tanjong Berhad were the key beneficiaries from the first generation IPPs. TNB itself planted-up 3,180MW of new capacity and these were at

Gelugor (330MW) and Janamanjung (2,100) in 2003 and Port Dickson (750) in 2005

The cost of reserve capacity is borne by TNB. Assuming TNB sold 70% of the IPP’s average load factor, the group bore RM1.3 billion of spare capacity cost in financial year 2007. This cost is a cost to be borne by the nation, not IPPs or TNB.

Decisions to install new capacity is not an IPP or TNB call but that of the government. A competent computation on tariff will incorporate the cost of spare capacity, say a reserve margin of between 20-25%. Anything in excess is a ‘penalty’ to the consumer and should not be incorporated into the tariff but paid for by the relevant authorities.

PPA structures and tariffs

To secure financing and meet reasonable shareholders returns, PPAs were put in place. This is an acceptable practice in both developed and developing countries where direct access to the consumer market is not made available to the IPP.

In Malaysia, two broad PPA structures exist:

• Take-or-Pay (‘TOP’)

• Capacity & Energy Payment (‘CP/EP’)

Under TOP, TNB will purchase an agreed contracted quantity of electricity from the IPP at an agreed unit price. There is no adjustment in this case for inflation.

Under CP/EP, there are two main elements:

(i) capacity payments which comprises Capacity Rate Financial (CRF) – a fixed element to cover debt service and a rate of return to sponsor and fixed operating rate (FOR) which is inflation indexed and covers fixed operating costs; and

(ii) energy payments which comprises (a) variable operating rate (VOR) inflation indexed and covers variable operating costs - and (b) fuel cost.

As long as an IPP meets the dependable capacity and available requirements in the PPA, TNB pays the full capacity payment irrespective of plant despatch level (ie, electricity generated and sold). This may result in some IPPs not being despatched but in receipt of full capacity payment.

In order not to cloud the commercial substance of the PPAs, whether it is TOP or CP/EP, the common factor is the effective unit tariff to TNB, ie, the price TNB pays for the quantity purchased from an IPP (aggregate revenue divided by aggregate output).

TNB’s overall cost per unit of electricity sold remained at 21.2 sen/kWh in the financial year ending August 2007. This cost per unit is expected to increase in the medium term, with rising coal prices remaining a key challenge to TNB.

TNB’s average tariff to end-consumers was 25.9 sen/kWh in 2007. TNB’s margin for transmission, distribution and profit is 6.1 sen/kWh.

IPPs account for 45% of installed capacity and assuming this translates to output purchased

the tariff revised on June 1, 2006 provided TNB with an additional RM1.5 billion (or 12% increase) in revenue.

Consumers had little choice but to accept this tariff revision due to the monopolistic nature of the industry. In a competitive, multi-supplier model and with supply well exceeding demand, tariff rates for consumers should trend downward.

This will serve to accelerate demand and moderate the reserve margin. The reverse occurs in the Malaysian context.

Key issues

TNB showed exceptionally good results for 2007 with net profit of RM4.1 billion, primarily due to the tariff revision (12%) in June 2006 and cost rationalisation. Results were not spectacular for the nine-month period in 2008 at RM2.88 billion due to higher operating expenses and foreign exchange translation losses.

The tariff adjustment of 25% on July 1, 2008 will impact upon results in 2009. Meanwhile, TNB faces key issues that need some form of resolution to keep profits on an even keel:

Obligations to IPPs - In the FY ending Aug 31, 2007, TNB paid a total of RM7.7 billion to the IPPs, of which 45% or RM3.5 billion comprised capacity payments. This will increase to RM6 billion by August 2010 upon full commissioning of Jimah’s plant.

But as long as consumers pay for generation, transmission and distribution costs, TNB should remain positive as a power trader.

Coal purchases - Under the government’s fuel mix policy, coal use is on the ascendancy from 8.8% in 2000 to 21.8% in 2005 to 36.5% in 2010. This is estimated to translate into a forex outflow for the nation of RM2.9 billion by 2010.

Although there is a compelling argument on gas depletion (which current estimates suggest will last for another 39 years), coal purchases/prices result in vulnerability in our forex/exchange rate.

Debt obligations - TNB’s total outstanding debts as at August 2007 stood at RM24.2 billion. This was further reduced in the first nine months of its financial year to RM22.5 billion. Of this, approximately 46% was denominated in foreign currencies.

Over-exposure and insufficient hedging mechanisms have contributed to significant exchange rate translation gains or losses annually.

Assuming 50% of all foreign currency borrowings are hedged, a 10% swing in exchange rate will still result in RM0.5 billion impacting on profit/loss. Assuming 50% of borrowings are fixed, floating-rate movements of 1% will result in RM113 million swing to the profit and loss account. Annual interest payments are reportedly RM1.2 billion.

Tariff adjustments - Instead of tariff adjustments being dependent on government approvals, a market-oriented, cost-reflective tariff formula could be devised that is transparent and applicable on annual basis. Industry and consumer inputs could assist in finalising this formula.

The key ingredients of the formula may include:-

• fuel mix policy [40 (gas) : 30 (coal) : 30 (hydro & others)];

• optimal reserve margin (say, 20–25%);

• fuel costs (gas, coal, diesel & others)

Under the present regime announced recently by the government, the gas price has been set at RM14.31/MMBtu, which represents a discount of 70% from the prevailing market price.

This discount will be reduced progressively at the rate of 5% a year and extinguished altogether from the 15 th year onward, whereupon the gas price paid by IPPs will be equal to the prevailing market price.

If the tariff payable by the end user is not adjusted, TNB’s operating margin will be eroded increasingly over time by:

• inflation on non-fuel operating costs;

• financing cost (interest rate);

• projected capital expenditure (for 5 years);

• capacity and energy payments to IPPs;

• TNB’s own generation costs;

• transmission & distribution costs; and

• contingency items

Way forward

The key elements ‘burdening’ TNB are IPP payments and forex translation loss. As mentioned earlier, a cost of reserve margin in excess of say 25% is not to be borne by TNB or IPPs but by the relevant authorities. TNB should have positive net revenue from sale of electricity to consumers even though it makes a significant payment to IPPs.

If this payment is too ‘burdensome’, it is perhaps in the government’s interest to establish a Power Trading Corporation (PTC) Berhad (under the energy ministry for example) to purchase power generated by the IPPs and sell this direct to consumers/industrial users in designated regions.

In other words, TNB is ‘relieved’ of its payments to IPPs and corresponding revenue from sales. PTC will operate and manage distribution/transmission in designated regions/areas.

In respect of forex translation gain/loss, it is conceivable for a special purpose vehicle (SPV) under an appropriate ministry or GLC, for example Khazanah, to acquire the offshore liabilities (loans) of TNB and TNB agreeing to pay RM-denominated payment streams to the SPV.

On TNB’s books, there will be no further translation loss/gain issues – only RM payment streams (to the SPV).

From a consumer’s perspective, so long as TNB remains a monopoly in transmission and distribution, consumers are not likely to experience a market-oriented, multi-supplier market.

One model to consider, in this context, is the UK model. The electricity industry in the UK has four main elements and these are:

Generation – responsible for generating the energy we use in our homes and businesses. Although historically, electricity generation was mainly derived from coal consumption, the UK generating industry has moved to a variety of generation methods – nuclear, gas etc. Generated electricity flows into the transmission network and through to the regional distribution networks.

Transmission – responsible for maintaining and operating the high-voltage transmission network. This network carries large amounts of power from the generators to the distribution networks – similar to the motorways of the country’s road networks.

There are three transmission licence holders in Great Britain – Scottish Power and Scottish & Southern Energy in Scotland and the National Grid in England and Wales. The National Grid operates the network access across Great Britain, but only owns the network in England and Wales.

Distributors – are the owners and operators of the network of towers and cables that bring electricity from the high-voltage transmission network to homes and businesses. Even so, they are not the organisations that sell electricity to the end consumer.

This is carried out by organisations who make use of the distribution networks to pass the energy commodity to your property – suppliers.

Suppliers – are the companies who supply and sell electricity to the consumer. The suppliers are the first point of contact when arranging an electricity supply to domestic, commercial and smaller industrial premises.

Competition in the UK electricity and gas markets was phased in over an eight-year period, due to the sheer size of the task in terms of the number of customers and the technical complexities involved. In April 1990, the first tranche of the electricity market, covering about 5,000 large customers with a maximum demand of 1MW and above, was opened to competition.

Ten years later, 81% of customers in this market were supplied by a non-local supplier. In 1991, British Gas also opened their market to competition with the first tranche affecting customers with a consumption in excess of 25,000 therms per annum.

The second tranche of the gas market was opened between 1992 and 1995, dependent on location and affected customers with a consumption of between 2,500 therms and 25,000 therms per annum. In April 1994, the second tranche of the electricity market, covering about 50,000 medium size customers with a maximum demand of 100 kW-1MW, was opened to competition.

This market competition has also developed well and now more than 50% of customers are supplied by a non-local supplier.

The last and the largest tranche of the electricity market covering about 26 million customers with an annual consumption of up to 12,000 kWh, so-called 'designated customers', including domestic and small business customers, was progressively opened up for competition between September 1998 and May 1999.

Slightly earlier, in May 1998, the domestic gas market, some 18 million customers, was fully opened to competition. By the start of 2001 around 11 million (38%) of domestic customers had switched supplier at least once.

Currently, about 100,000 electricity customers are switching supplier each week, of these 56,000 in net terms are choosing to leave their former regional supplier, according to the latest the Office of Gas and Electricity Markets (Ofgem) figures.

In the Asian environment, Malaysia was among the pioneers to implement IPPs and finance them through the local bond/commercial lending market. This was a step in the right direction. Electricity generation has several players but the same process has not taken shape at the transmission and distribution levels.

It is in the nation’s interest to move forward on ‘bidding’ process which will ultimately include the consumer, ie, the consumer having a choice of selecting an appropriate package/product. That will surely lead to a more efficient electricity market and a more market-oriented TNB.

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