It is the clearest timetable yet for deregulation in the highly regulated electricity market since a blueprint was outlined in 2002.

The reform aims to enhance operating efficiency via competition and lower power prices by reducing the spare generating capacity that needs to be invested by shifting more excess output to under-supplied regions.

Hu Xinmin, a senior manager at electricity industry consultancy The Lantau Group, said there has been some delay in the pace of deregulation in some regions owing to the need to build auxiliary infrastructure.

“When the NEA approved the blueprint for the establishment of the Beijing-Tianjin-Hebei regional power market, spot market trading was intended to be introduced concurrently,” he told the Post.

“But the local grid operators have voiced opposition on network security concerns, given it takes time to set up the information technology and network communication systems to enable trading.

“Before, the grid operator only needed to send power dispatch instructions to the generator once a day ... with market liberalisation it needs to be done hourly,” he said. “Not only that, more monitoring is required to ensure compliance.”

Similar to train traffic control at a subway station, manpower and sophisticated information systems are required at power grid dispatch control centres to cope with the needs of more complicated power trading and dispatch after price liberalisation.

“The volume of work on dispatch planning and execution will rise and the reaction time for dealing with potential unexpected incidences will diminish,” he said.

A September circular issued by the National Development and Reform Commission (NDRC) which oversees the NEA, said it plans to kick off reform in the eastern, central, northeast and northwest China and Tibet regional power grids next year, after launching tariff revamp trials in 14 provinces and autonomous regions in September and 18 others earlier.

It said it will push forward “orderly market reform” in power pricing by “gradually expanding market pricing in wholesale and retail tariffs to more regions”, establish rules and regulations and monitor power trading.

It will also study the launch of a mechanism and instruments for companies to hedge their exposure to power price volatility.

When the reform is complete, transmission and distribution tariffs will continued to be regulated but monopolies State Grid Corporation of China and China Southern Power Grid would no longer enjoy fixed profit margins regardless of operating costs, since their tariffs will be set on a “cost-plus-reasonable return on approved assets” formula, and incentives will be given for them to cut costs.

For power generators, their selling prices will no longer be set by the state and will gradually be subject to market competition either through negotiations with large end-users or with retailers, according to the NDRC. The distribution segment will be opened to new retailers as the last-mile state-owned distribution monopolies are broken up.

After two years of reform the biggest progress has been made in direct trading between generators and large industrial users, which saw generators cut prices to grab market share amid oversupply.

According to a China Merchants Securities research report, some 20 per cent of the nation’s coal-fired power output has already been subjected to market-based pricing this year, a ratio predicted to rise to 50 per cent next year. The remainder is subject to state pricing.

The NEA has a target to see all power used by the industrial sector become market-priced in 2018 and for the same to happen in the commercial sector by 2020.

Hu said it is questionable whether such targets can be reached, unless a spot market can be built quick enough and proven to work well.

“The need for a spot market will become increasingly critical, because once the market is deregulated, buyers and sellers will be bound by their contractual obligations,” he said. “Because the buyers have to project their demand one month in advance under the current monthly trading scheme, there will always be a gap between their forecasted volume and actual demand, and the gap needs to be settled by spot market trading.”

Dennis Ip, Daiwa Capital Markets’ China utilities research head, who gave China’s power generation sector a “negative” investment recommendation rating in a recent report, said the price discounts for coal-fired power are running at 10 to 15 per cent to the state-set benchmark tariffs.

With overcapacity set to worsen in the next two years since demand growth is expected to be weak and more coal-fired plants are expected to come on stream, plant utilisation, power tariffs and project returns will continue to fall, he believes.

“With the overall capacity additions likely to far outpace power demand growth, the implication is that the utilisation hours for most types of power – especially coal-fired and nuclear – is likely to decline,” he wrote.

Ip expects demand growth to slide to 1.5 per cent next year from 4.5 per cent this year before picking up to 2.6 per cent in 2018 as ongoing rebalancing of China’s economy reduces its energy intensity.

He forecasted that project return rates for coal-fired power plants would fall from 9 per cent this year to 5 per cent in 2018, while those of ground-mounted solar farms would slide from an average of 8.2 per cent to 5.9 per cent, and those of wind farms to be relatively steady at about 8 per cent.

Although wind and solar farms are protected by certain guaranteed utilisation hours by the government, operators are under pressure to agree to sell more output in the open market at sharp price discounts to augment meagre return rates.

But regulators are unlikely to fully let go of their power on prices, Hu said, noting the final draft of trading rules issued by the Guangdong government has given it the power to set minimum prices at times of “severe oversupply” to avoid “cut-throat competition”.