Sarawak's Murum hydroelectric project came online this year
Sarawak’s Murum hydroelectric project came online this year Credit: Sarawak Energy

 

With economic growth driving the need for more energy, Malaysia has set out plans to meet this demand while at the same time changing the way it generates and delivers electricity, writes Jeremy Bowden

 

With Malaysia boasting average GDP growth of around 6 per cent for the last four years – edging up to around 6.2 per cent in the first three months of this year – economists remain bullish about this Southeast Asian nation’s newly industrialized market economy.

The strong economic growth is driving demand for electricity, which – according to state power company TNB – is expected to grow at an annual rate of 3 per cent up to 2030, when per capita demand should reach the OECD average.

Malaysia has always seen its power sector primarily as a strategic resource and an essential input to the economy. In May the Prime Minister, Najib Razak, reaffirmed his support for TNB’s dominant role in providing reliable and affordable power to fuel the country’s “quest to become a developed nation”. He also defended a recent hike in tariffs, noting that TNB’s capital expenditure – required to expand production capacity and keep pace with demand – had been larger than its profits for some time, requiring loans to make up the difference.

But in opting to maintain a power sector dominated by a state generator and operator, alongside independent power producers (IPPs), Dr Razak is continuing with a model perhaps more associated with developing countries than a developed one.

However, while TNB remains responsible for the transmission, distribution and nearly half of the power generation in Peninsular Malaysia, its role as system operator and single buyer is in the process of being ring-fenced to enhance transparency, independence and fair play in generation scheduling and dispatch.

In addition, TNB has been divided into five business entities in anticipation of full implementation of incentive-based regulation (IBR) in 2015.

The IBR is meant to “enhance operational efficiency and transparency towards maintaining a reliable and sustainable electricity supply”, according to Malaysia’s Energy Commission. It includes the introduction of a fuel cost pass-through mechanism (FCPT), which will allow power prices to move in line with fuel costs. This will stabilize TNB profits and help it to meet CAPEX obligations: “With the implementation of the IBR and FCPT, it is anticipated that the fuel cost risks are mitigated, therefore leading to better earnings predictability for TNB,” the company said.

Over recent years, Malaysia and TNB have managed to maintain a healthy reserve margin of around 6 GW, or 20 per cent, against quickly rising demand. Prices and costs have been kept low by cheap domestic gas, power price control and subsidies, but this fuel cost advantage is fast disappearing as domestic gas reserves decline and the country becomes increasingly reliant on international coal and liquefied natural gas (LNG) markets for its fuel supply.

So while Malaysia may not be moving in the competitive market direction in generation or retail, it is recognizing that maintaining a costly subsidy system is becoming less and less affordable.

Effective from 1 January of this year, electricity tariffs were raised by an average of 15 per cent to help phase out energy subsidies through the Subsidy Rationalization Programme.

However, this has been the only rise since June 2011, and was unpopular among sections of business and the public even though many consumers enjoy discounted rates. More such politically sensitive rises are needed, as the government will still have to spend RM14 billion ($3.6 billion) annually on subsidies and rebates, according to the minister for Energy, Green Technology and Water, Dr Maximus Ongkili.

In its financial year ended in August 2013, TNB’s CAPEX was Rm8.5 billion, against a net profit of Rm4.61 billion on RM37.13 billion in revenue. TNB is only able to sustain borrowings to make up the difference if returns are stable – underlining TNB’s need for the ICTP.

Figure 1. Capacities by status (MW). Analysis based on the selected power plants
Figure 1. Capacities by status (MW). Analysis based on the selected power plants

TNB has also incurred substantial losses on occasions when state oil and gas company Petronas had to cut gas supply for technical reasons, forcing TNB to switch to more expensive distillates. In response, the government has floated proposals to allow third-party access to the country’s gas networks to ensure more stable supply.

Figure 2. Capacity planning, by status (MW). Analysis based on the selected power plants
Figure 2. Capacity planning, by status (MW). Analysis based on the selected power plants

Some private investors in IPPs have always been shielded from fuel price risk, as their deals included long-term fixed-price gas supply deals with Petronas. Such attractive terms had led to criticism that some of the older IPP deals were overly generous. An increased use of direct negotiation – as opposed to competitive tendering – in some awards is once again making the IPP process controversial.

In terms of generation mix, the country is set for ever greater reliance on imported coal, which is normally cheaper than LNG. This is despite the fact that Malaysia still exports large quantities of LNG to northeast Asia. The price it gets for that gas is among the highest in the world, which means the opportunity cost if it were to be used at home is very high, and in any case much of it is locked up in long-term supply deals. The once strong enthusiasm for nuclear energy – including two 1000 MW units by 2021 – collapsed in the wake of the 2011 Fukushima disaster in Japan.

Nevertheless, Malaysia does still have a few aces up its sleeve. Gas/LNG is not the only energy resource present in Sarawak, where new hydropower projects, including the 2400 MW Bakun plant, are now operating. It is unlikely to bring any immediate benefit to Peninsular Malaysia, however, as plans for an interconnector have been put on hold for the time being, and the power will be directed to local consumers in Borneo, including a major new industrial park.

Other plans to bring in power from the Indonesian island of Sumatra have been proposed but are fraught with complications, while links are being strengthened with neighbouring Thailand (see interconnection table, right).

More gas may be present in Malaysia, but some commentators complain that overseas exploratory interest has been distracted by the rise of the unconventional gas sector, drawing potential investment elsewhere. This leaves Peninsular Malaysia ever more reliant on international markets for its fuel supply, and this – along with the implementation challenges of nuclear and some renewables – has left TNB and the government increasingly concerned over energy security, as well as costs.

Gas- and coal-fuelled production currently represent around 40 per cent each of Malaysia’s total, with the remainder split between hydro, oil and renewables. On the demand side, the industrial sector has historically dominated electricity sales, but has seen a steady decline since 1990, falling from 47 per cent then to 44 per cent in 2011 and a predicted 41 per cent by 2020. The commercial sector is expected to overtake the industrial by 2030.

Controversy over IPPs

In the absence of a competitive market, IPPs are seen as providing an essential source of private capital, as well as maintaining pressure on TNB to keep its costs under control. But public concern over the IPP model has resurfaced in the face of a move away from competitive tendering and towards direct negotiations with some potential investors.

There has been particular concern over a move to award the Johor power plant Track 4A to YTL Power International, a company thought to have benefited from generous terms in power purchase agreements (PPAs) signed in the 1990s.

However, both the issuing process and the terms of the agreements have evolved since the first and most generous IPP contracts were handed out by TNB. As a result, analysts say new IPPs now yield internal rates of return on average around 7-8 per cent, compared with the mid-teens for early deals.

The government is also renegotiating the early IPP contract terms as they near expiration in 2015-2017, and new lower rates are expected to accompany lengthy contract extensions.

However, according to some in the industry, only around 2250 MW of the 4000 MW contracted out by the original six contract holders will be renegotiated.

YTL has since withdrawn from the 4A project bid, but concern remains that other IPPs will be awarded in a less than transparent manner. Already the direct negotiation approach has been extended beyond coal and gas plants. Earlier this year, state developer 1Malaysia Development Bhd (1MDB) signed a 25-year PPA through direct negotiation with TNB, for power from a 50 MW solar park in Kedah – the largest in the country (see renewables box, page 12).

And in February, 1MDB (and Mitsui) won an estimated RM12 billion deal for the 2000 MW coal-fired power plant Project 3B – due onstream in 2019 – after negotiations with government entities, following a competitive tender process involving five bidders.

Early in the tender process, TNB had been the clear favourite, with Malakoff the other front-runner. YTL was the other unsuccessful bidder. 1MDB already owns Tanjong Energy, a 75 per cent stake in Genting Sanyen Power (now known as Kuala Langat Power Plant or KLPP), and a 75 per cent stake in the coal-powered Jimah Energy.

In 2011, the government increased the allowable percentage of foreign ownership in IPPs from 30 per cent to 49 per cent. The move encouraged 40 companies to bid for the 4500 MW Prai power plant tender. Despite this, in October 2012 TNB was awarded an Rm3 billion contract for the first 1000 MW-1400 MW stage. In total there are about 27 licensed IPPs operating in the country, with over 15 GW of capacity.

Gas-fired plants such as the Paka CCPP generate around 40 per cent of Malaysia's energy
Gas-fired plants such as the Paka CCPP generate around 40 per cent of Malaysia’s energy Credit: Siemens

More coal on the slate

Gas supply interruptions are being made worse by fast-depleting domestic gas fields, leading to supply shortages. In a recent presentation TNB said that although combined-cycle gas turbines were the most competitive form of generation for baseload based on current domestic gas prices, as the gas price gradually moves towards the international market price, “coal-fired plants are expected to take over as the cheapest option for baseload, with over 60 per cent of generation expected to be from coal in 2019 before dropping back with [power] imports from Sarawak and nuclear”.

Malaysia’s rising appetite for coal comes as a number of other major Asian economies are seeking to increase reliance on imported coal, leading to growing competition for supplies and upward price pressure.

Domestic power producers burn about 23 million metric tonnes (mmt) of coal annually (all imported), and this is expected to rise to 37 million mmt by 2020. By that year, coal-fired electricity is expected to make up 42 per cent of Malaysia’s total generation capacity, compared to 33 per cent now.

Malaysia buys about 70 per cent of its coal from Indonesia, with Australia and South Africa contributing most of the remainder – all through TNB, the sole coal importer for the power sector. Many other regional consumers also buy from Indonesia, the world’s top thermal coal exporter with over 300 mmt annually. That figure is expected to jump by 50-60 mmt in 2014, but there are signs that Indonesian supply growth is slowing.

Any policy change in Jakarta – such as moves to increase royalties or a recent proposal to ban exports of low-grade coal from 2014 – could hinder the security of future supplies.

Some analysts have been advising TNB to secure overseas coal assets, as India and China have done by snapping up coal mines in Australia and Indonesia. TNB Coal International once owned a coal mine in Kalimantan, but ceased operations in 2007.

Political risk

Malaysia is fast moving towards developed nation status, both in terms of economic power and electricity consumption. It is also having to face the problems of maturity associated with declining domestic energy resources, reflected in rising fuel costs.

Linking prices to fuel costs will help control rising debt while maintaining capacity expansion, but public pressure will make any price hikes fraught with political risk.

Eventually, if it is able to bring power prices into line with international energy prices, there is the option of a more competitive market or even part-privatization of TNB, but at this stage that looks some way off.

East Malaysia

Serving much smaller and more dispersed populations, Sabah and Sarawak’s power providers have experienced dynamic change in recent years.

Part of its efforts to promote itself as a heavy industrial destination, the Sarawak Corridor of Renewable Energy (SCORE) strategy involves a massive increase in capacity generation. Projects include the 2400 MW Bakun hydropower plant (HPP), which came fully onstream in 2013; the 944 MW Murum HPP (operational by this year); the 150 MW Limbang HPP (2013); the 1000 MW Baram HPP (2015), and the 400 MW Pelagus (2016) and the 1400 MW Baleh HPPs (2019). Additional coal-fired thermal power plants are also in the works.

Sabah Electricity (SESB) has access to gas as well as hydropower options, but has been hit recently by production shortfalls due to operational difficulties and cuts in gas supply from Petronas. SESB operates 410 MW of installed capacity, supplemented by seven IPPs with 630 MW.

Renewable rationing

Solar development has been Malaysia’s most popular renewable category by far, but a limit on the size of solar installations and rationing of applications has kept a lid on capacity growth.

The Small and Renewable Energy Programme (SREP), established to monitor the renewable energy industry, allows output of no more than 10 MW per solar project to be sold to the grid through TNB, and has still had to restrict applications due to budget constraints.

As a result, many developers are calling on the government to lift the cap, review what has become a very generous feed-in tariff (FiT) system and introduce scaled tariffs.

However, as noted above, the government has also moved forward with some direct deals, including the award of a 50 MW plant to 1MDB. While the tariffs were not disclosed for that deal, observers put likely rates at about half the level of deals done in January 2012 at around 95 sen/kWh ($0.31/kWh) for solar farms with a size of 1 MW-10 MW, under the FiT system introduced in December 2011. The lower rate takes advantage of economies of scale associated with a 50 MW plant.

Renewable energy accounts for only about 1 per cent of total output in Malaysia (not including hydro, which makes up around 10 per cent), although the government had set a target for renewables to account for at least 5.5 per cent of power generation by 2015.

In addition to solar and biogas, new hydropower projects are coming onstream, such as the 250 MW Hulu Terengganu hydropower plant, targeted for operation by September 2015, and the 372 MW Ulu Jelai plant, scheduled to come online in December 2015.

Jeremy Bowden is a journalist focusing on energy matters.

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