The world seems to be getting hooked on investing in China, and China's power sector has often been cited as one of the best ideas around for portfolio investors. The power outages in some 21 of China's 31 provinces indicate near-term upside, while projections of huge demand and growth potential portent valuable long-term potential. After all, China's electricity output per capita is a mere 1,278 kWh compared to the United States' 13,958 kWh or even South Korea's 7,068 kWh.

Most investors are already quite aware of some of the risks involved, such as a widely forecasted slowdown in China's economic growth. It is also well-known that the market reforms currently underway make the regulatory future uncertain and probably less profitable for Independent Power Producers (IPPs).

There are however some lesser-known issues that should give investors pause. The Chinese power industry faces unique structural pressures, and profitability of power producers is not guaranteed even in the face of recurrent energy shortages.

Coming Soon to a Grid near You: Glut

A real risk of electricity oversupply exists, given the furious rate at which capacity is currently being added. Since mid-2003, the Chinese government has revised the country’s capacity addition plan upwards, from 400GW to 430GW.

This bears an uncanny resemblance to the situation in the mid-1990s, in which capacity was continuously added in response to power outages. This phase of zealous building was swiftly followed by a fall in the average dispatch factor to an all-time low between 1998 and 1999. Many foreign (direct) investors were burned so badly they pulled out of the country entirely, selling their investments at bargain-basement prices. China’s power sector is no less vulnerable to boom-and-bust cycles than any other country’s, and making accurate projections in China is probably even more difficult. The question remains: is the current building spree going to lead to another glut?

The utilities team at ING Financial Markets estimates that China’s gap between power shortage and overcapacity is about 5 years, and 2002 and 2003 represents the start of the cycle. This suggests that equilibrium, and even overcapacity, may start to kick in around 2006-7. Furthermore, factors leading to the recent history of tight supply should be examined closely. For example, the later part of 2003 saw relatively serious droughts and low utilization levels of hydropower plants. In addition, the timing of the droughts coincided with the usual end-of-year shutdown of many plants for overhaul maintenance. As such, the severe power outages at the end of 2003 could be caused partially by spikes in demand, rather than long-term demand growth.

Moreover, the problem of balancing electricity supply-demand is exacerbated by the widespread use of coal-fired power plants to fill in the peak loads, especially when the base-peak load gap is widening substantially. A good example of how this capacity addition strategy has backfired can be found in Shandong. During the mid to late 1990s, more than 6,000 MW of new coal-fired capacity was planned in Shandong by the year 2003. The use of coal-fired plants as peaking units can be gleaned from the 1999 prospectus of Shandong International Power Development. The prospectus discussed ambitious plans for capacity addition, even citing the addition as hardly sufficient, with a projected shortage of 375 MW in the Shandong provincial grid at peak demand even after the expansion. Perhaps unsurprisingly, in 2003 Shandong ended up with the highest reserve margin in China at a time when the national reserve margin was at a historical low.

In general, gas-fired plants are more appropriate and economical than coal-fired plants as peaking units, due to lower construction costs and short start-up time to full load. Nonetheless, the practice of using coal-fired power plants for peak loads may persist, given that the gas-fired plants in China face unique cost and pricing pressures compared to other countries. According to Philip Sin at Deutsche’s global utilities research, the total costs per MWh for a coal-fired plant and a gas-fired plant with similar generation output in China is US$30.60 and US$43.80 respectively. The huge discrepancy is largely a function of abnormally high local natural gas costs, and the fact that the advantages of gas-fired plants – the lower environmental impact, its shorter development time, and higher fuel efficiency – are for various reasons not being sufficiently priced into the equation.

The higher cost of natural gas is not merely due to its relative scarcity compared to China’s vast coal resources. Weak oversight or lack of central policy with regards to regulating the gas industry has led to many players along the “pipeline” taking a cut out of the gas business – a fact evidenced by the plenitude of local governmental taxes, surcharges, processing fees, pipeline transportation tariffs, etc. While the cost of coal is also increased by the imposition of some local taxes (which is as high as about 30% in Shanxi alone), there can be up to 16 different kinds of taxes payable for Sichuan gas!

As such, gas-fired plants are likely to remain few and far between for some time. It is a matter of guesswork as to how long the Chinese government will take to undertake pricing and fiscal reforms relating to the gas industry, internalize the environmental externalities of gas-fired plants, and create incentives for its development. It could be that such matters would be accelerated as the government-mandated US$17.6 billion West-East Pipeline nears completion. Nonetheless, in the meantime, coal-fired units are still being constructed for peak shaving – a problem affecting the supply-demand balance.

Nonetheless, in the face of this risk of over-building, it is important to remember that investors could be thinking: even if a glut of power occurs in the near term (a la the 1998-9 glut), it should be absorbed over the life of the asset. Moreover, from the government’s perspective, it is probably less expensive to overbuild (than suffer power shortages) and let demand catch up in the long term. The main problem with such attitudes lies in estimating whether future demand will materialize quickly enough to cover up front capital costs and prevent credit defaults.

Rising Costs versus Regulated Tariffs

Another material risk affecting China’s power industry is the rising cost of electricity generation coupled with uncertainty over whether generation tariffs can be adjusted upwards to protect the profit margins of IPPs.

In terms of rising cost elements, pollutant discharge fees are gradually increasing, nibbling away at the margins of IPPs. In certain provinces such as Guangdong, more radical moves have been taken, with announcements that all power plants with an installed capacity above 300 MW are to install desulphurization equipment. It is believed that smaller power plants in these provinces will soon be required to retrofit scrubbers as well.

Furthermore, equipment costs in general may be on the rise, given that the current low profitability of equipment manufacturers is unlikely to be sustainable. Already, according to Goldman Sachs research, capital equipment costs have risen 15% to 20% in the last six months and that production capacity for power generation equipment is close to 100% utilized. Escalating steel prices will probably aggravate the situation. Such rises in capital costs will affect plants which have not entered into equipment contracts.

The threat of increasing coal prices poses a graver concern for IPPs, as coal accounts for 50-60% of total operating costs. Though IPPs try to lock in about 65-85% of their annual requirements with term contracts, the remainder has to be sourced from the spot market. There are two main reasons why coal prices will probably trend higher to more than 6%.

First, since 2002, China’s coal mining sector has been increasing production at 20% a year- which, given the limited ability to open new mines and increase productivity, does not seem sustainable. As output growth slows down, a rift between supply and demand is likely to drive up prices. Second, much of the current coal supply comes from small, unsafe township-run mines with poor safety records. A major reason for the coal shortage in 2003 was a sudden government decision to shut down many small mines under popular pressure following an excess of fatal accidents. Although 70% of these closed mines resumed operation towards the end of 2003, mass mine closures could recur and tighten supply. In any case, governmental efforts to improve the safety feature of Chinese coal-mines will imply higher capital expenditures, and thus higher production costs and coal prices.

Taking a deeper look, the vulnerability of IPPs to increasing fuel costs reveals an underlying structural problem in China: the coal industry has been deregulated and subject to open market competition since 1993, while tariffs in the power industry continue to be highly regulated, creating a ceiling on revenues while costs are allowed to escalate freely. While the government still wields some influence over price negotiations to favor IPP customers, there is no guarantee that it will necessarily exert direct pricing pressure on coal producers.

To counteract rising coal prices, the Chinese government is instead planning to consolidate the coal industry to build 10 mining conglomerates, each capable of producing more than 50 million tons of coal annually. This will hopefully lead to economies of scale and thereby lower costs. However, this restructuring will probably take much time to implement, and in the meantime, IPPs will have to bite the bullet of potential coal shortages and price hikes.

In the midst of rising costs, will IPPs be allowed by the government to pass on the costs to end-users through increases in tariffs? Of late, many commentators have remarked that the Chinese government will try to protect the profit margins of IPPs by permitting upward tariff adjustments. They cite the National Development and Reform Commission (NDRC)’s decision in December 2003 to raise tariffs by around 2% to pass through an approximate increase of 7% rise in coal prices.

However, tariff setting in China is an extremely complex and sensitive matter involving several governmental agencies and stakeholders with conflicting interests. Even if the central government through the NDRC makes a decision to increase generation tariffs, it may not be implemented universally, if at all. For example, the NDRC’s announcement to raise tariffs in July 2003 was never implemented. And even the implementation record of the December 2003 order was imperfect. Shandong has won approval to not proceed with the tariff hike.

There are three major downward pressures on generation tariffs. First, the unbundling of generation and transmission will eventually lead to grid companies seeking commercially-acceptable returns on capital, or at least returns at a level high enough to finance overhauls of the antiquated grid and interconnection projects. Calculations from JP Morgan suggest a funding gap of about RMB 56 billion, which can translate into generation tariff cuts of 2-5% (up to 8%). This problem is due to a historical economic distortion dating from when the State Power Corporation was the one and only integrated electrical utility, and there was no internal service price for transmission service.

An increase in grid margins will have to result in either generation tariff cuts or end-user tariff hikes. The former is probably more viable, as end-user tariffs are already relatively expensive. According to statistics from UBS, the affordability of electricity (using the price of electricity as a percentage of per capita GDP) in China is roughly 4.9%, compared to 0.2% in the United States and 0.5% in Hong Kong. Thus, an increase in end-user tariffs will probably meet with much opposition by local authorities, given its negative impact on state-owned enterprises (which tend to be the most inefficient and energy intensive) and even foreign investment (since China’s competitive advantage lies in its cheap industrial production costs).

Second, there is a limit as to how much end-user tariffs can be adjusted upwards, as end-users can react by turning to cheaper captive generators that can be built without the need to connect to the grid or support unprofitable and aging sister plants. Already, many industrial parks in Shandong (which has one of the highest end-user tariffs in the country) have obtained state approval to build their own captive plants, disguised under the nameplate of “co-generation plants”. This has spurred a joke that in provinces like Shandong, “cogen rules, not gencos”.

Finally, IPPs, which currently enjoy high generation tariffs, will face competition from cheaper power suppliers in inland provinces as a result of the West-to-East transmission scheme. Guangdong will be importing cheap hydropower from Yunnan in 2005 – a development likely to subject existing Guangdong IPPs to tariff cuts. This is because wholesale tariffs for power from Yunnan to Guangdong would be RMB0.32/kWh, inclusive of transmission fees, versus the current average on-grid tariff of power plants in Guangdong of RMB0.38-0.4/kWh.

Elsewhere, Shandong’s high tariffs will soon be rationalized to the same level as the North China Network, since it has been recently regrouped with the latter network where average generation tariffs are about 5-10% lower.

Caveat Emptor!

To conclude, China’s power sector is fraught with fundamental problems ranging from a chronic electricity supply-demand imbalance to rising costs which may not be covered by higher generation tariffs. It is, therefore, of utmost importance to exercise caution and not confuse strong revenue growth for a good profitability profile.

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