Energy

Beijing introduced two credit trading systems, one aimed at improving the overall fuel economy of gasoline vehicles and the other to encourage NEV investment and wider adoption, as additional incentives for auto manufacturers.

The fuel economy credit system works like this: each car producer will be scored based on the difference between its fleet’s fuel economy and government-determined targets. If the fleet’s fuel economy is below the target, then the auto maker will receive negative credit and needs to purchase credit from auto producers that have exceeded the government’s fuel economy standard, which is closely based on the US Corporate Average Fuel Economy (CAFE) standard. Beijing has drafted 2020 fuel economy target for cars of different types and weights. For each automaker, their average fleet fuel economy target for 2020 is calculated based on the assumption that all the vehicles they manufacture have met their respective targets. In addition, Beijing also requires the average fleet fuel economy to be within 120% and 110% of the 2020 target by 2018 and 2019, respectively.

A parallel credit scoring system has been established for NEVs, which has been modeled after the Zero Emissions Vehicle (ZEV) program implemented in California. Each automaker is required to earn a certain “ NEV score” that is based on the production volume of NEVs. That score, when divided by total vehicle production, must be larger than 10% by 2019 and 12% by 2020. Otherwise, the automaker needs to purchase additional credit from other automakers that have produced more NEVs above the requirement. The NEV program gives different credit scores based on various factors such as the specific type of NEV and the designed mileage. For example, a pure electric vehicle designed to run 300 km can earn 4.4 credits, while a plug-in hybrid with lower mileage will earn just two credits. As most NEVs will be able to obtain a score larger than one, to meet their 2019 and 2020 targets, auto manufacturers only need NEVs to account for between 2% to 5% of their total production. To put this into perspective, NEV production currently accounts for less than 2% of total car production in China in 2016, and NEV production is concentrated in just a handful of major automakers. This uneven production distribution means that the new NEV requirement will be challenging for certain auto manufacturers.

Since most domestic car manufacturers, including foreign-invested auto joint ventures, currently cannot meet their NEV target requirement, investment in better technology is expected to rise rapidly to improve NEV efficiency and meet the fuel economy standards. Beijing hopes this push will catalyze domestic car manufacturers to narrow their technology gap with global leaders.

The rapid growth of Chinese car ownership, averaging around 17% over the last decade, has made China the world’s largest auto market. But at the same time, that growth has also led to the country importing about 60% of the oil it consumes. Ten years ago, China’s annual import of crude oil was about 163 million tons, which has since more than doubled to 380 million tons in 2016. The growing reliance on foreign oil has become a source of national security concern for top policymakers. Moreover, improving the fuel economy of the overall auto fleet and increasing the adoption of NEVs will certainly have a positive impact on mitigating air pollution and carbon emissions, particularly as the transport sector is becoming a major contributor to air pollution in urban China.

Up until recently, electricity had been distributed mostly through administrative allocation for different types of end users. That is, different classes of end users received different priorities and prices. For example, important industrial users got guaranteed electricity supply at administratively set prices. This kind of administrative system stifles competition and biases against the more efficient power generators or renewables.

Part and parcel of power sector reforms, power generators and distributors, as well as end users and grid operators, are encouraged to sign mid- to long-term contracts rather than rely on administrative allocation of electricity.

Previously, how much electricity a power plant should generate each year was also administratively determined. The government now hopes to reduce the portion of planned power generation in total electricity generation. For coal power plants, for instance, their annual power generation quota—or the amount of electricity that gridcos guarantee to buy—will be cut by 20%. All new coal plants should sell their electricity through the market exchange.

In addition, renewable energy generators will still receive government protection. Gridcos are mandated to purchase a certain amount of renewable energy and must prioritize renewables over coal-based electricity.

As a result of weak demand for coal in the past few years, many coal mines have experienced financial distress and some have shut down. Coal of course remains the life blood of the Chinese economy, and the majority of coal mines are state-owned and the entire industry provides millions of jobs. Therefore, the central government has clear incentives to prevent coal prices from collapsing.

Meanwhile, since coal is also a major input cost for steel production and power generation, high coal prices will also have a negative downstream impact on industry and the real economy.

In a bid to devise a balanced solution to this near-term challenge, the new pricing policy set a price range for coal until 2020. That is, the coal price will be market determined as long as it is within the price band of ¥500-¥570/ton ($72-$82/ton). Once the price moves above or below this band, Beijing will intervene, especially when the price rises above ¥600/ton ($86/ton) or dips below ¥470/ton ($67/ton).

However, since China’s coal is widely traded and its prices are already largely market based, whether this policy will be effective remains to be seen.

The central focus of the energy plan is to constrain the growth of coal. The macro and binding targets of reducing energy intensity and carbon intensity by 15% and 18%, respectively, serve the dual objectives of limiting coal and aligning with China’s Paris climate change commitments. In addition, secular trends will also make it easier for China to achieve some of these goals, as economic growth is expected to average 6.5%, along with slower energy consumption growth of just 3% a year through 2020, about half the rate of the last decade.

Many factors, foremost environmental pollution, have driven the Chinese government to take serious actions to diversify from a coal-based economy. While coal will become a smaller share of total energy consumption, absolute coal consumption will still increase as total energy production will rise. However, a greater percentage of coal will be used for power generation, which is considered to be less polluting than coal consumption in the steel and chemical industries.

As coal power already faces overcapacity, the government has also issued a two-year moratorium on approvals for new coal-fired plants. Beijing hopes these measures collectively will be able to keep coal consumption growth to under 1% during this five-year period.

The gradual shift toward a credible energy market, in which market pricing for energy and more competition in previously monopolized sectors will become the norm, will also play an important role in achieving the broader objectives of the energy plan.

Inter-provincial natural gas transmission tariffs will also be calculated based on a “cost-plus” model, so as to ensure pipeline operators can earn an 8% return on their investment. The National Development and Reform Commission will regularly review and approve the pipeline operating cost, which is intended to regulate the gas transmission price to the end user.

Deregulation of the power distribution segment—which are the lower voltage power lines that connect from the main transmission trunk line to the end user—will be incremental.

One step forward that end is allowing private investment to enter the power distribution segment and auctioning off the right to build new distribution infrastructure. To encourage competition, investment opportunities in electricity distribution networks will be open to private investors and the distribution tariff will be regulated based on the “cost-plus” principle. To prevent anti-competitive behavior, distributors and retailers, in principle, should be separated, and generators are not allowed to build exclusive distribution networks.

However, distribution networks that are currently owned by the grid companies (gridcos) are not subject to this new policy, which implies that investment opportunities may be limited because the gridcos already own the majority of dispatch networks.

China has been attempting to reform gasoline prices for years, typically through various pricing formulas to make gasoline prices at the pump to more regularly respond to the market price for oil. This change, compared to previous gas pricing tweaks, involves the introduction of a price floor for retail gasoline—meaning that when the global oil price drops below $40/bbl, the government won’t lower the retail gasoline price, keeping it artificially high.

This is meant to support national oil companies and their refiners. Because China now imports more than half of its oil, the price floor allows domestic refiners to capture potential windfall profits when oil price drops below $40/bbl. The additional profit is intended to be channeled into a centrally managed special fund that will be used for industry and product upgrades, energy security and conservation, and emissions reduction.

The plan is unambiguous about bolstering the role of renewable energy in China’s primary energy consumption, including the ambitious target of increasing the share of renewables in electricity generation to 27% by 2020, up from 21% in 2016.

Beyond quantitative targets, the plan proposes incentives to lower the cost of wind and solar power so that they are competitive with traditional fuels like coal. Through a combination of renewable energy credits and the creation of a carbon trading scheme, Beijing hopes to use more market tools to catalyze the sector’s development and to gradually withdraw subsidies when renewables reach grid parity.

Another challenge is the curtailment problem—idle renewable energy that’s not connected to the grid—which has recently worsened and may discourage large investments in renewables. To address curtailment, the central government, among other measures, plans to mandate that coal power plants buy renewable energy credits and to encourage grid companies to improve dispatch and prioritize renewables during non-peak demand periods.

As a key component of deregulating the power sector, creating an effective electricity trading mechanism is meant to facilitate fairer market competition. While these exchanges will start as select pilots, including futures and derivatives trading, they are expected to be adopted nationally after successful trials. Eventually, it is expected that government-set electricity prices will be fully phased out.

Independent exchanges will allow for trading in both the spot and future markets for electricity, and larger industrial and commercial users can sign long-term contracts. This policy apparently applies to all new commercial and industrial end users, which will no longer be subject to set electricity prices and should either buy electricity from the exchange or directly from generators. Trading can also take place across regions and provinces, which will require integrating technical standards and getting support from ancillary services.

Currently, gridcos pocket the difference between the price they pay generators and the retail price they charge end users, which is how they derive the majority of profits. In addition, gridcos are usually the sole buyer of electricity from generators and are also the only wholesaler of electricity, meaning they effectively controlled the spread between the price it pays generator and charges consumers. In addition, plenty of cross subsidies exist between industrial, residential, and agricultural electricity prices. And within each type of end user, there are also cross subsidies among different voltage levels.

The bottom line on the electricity pricing reform is to limit the gridcos’ monopolistic practices by separating transmission from distribution/wholesale. The intended outcome of this reform is to allow power generators to sell directly consumers so the on-grid tariff is no longer controlled. At the same time, gridcos will be guaranteed a fixed transmission rate on the volume of electricity supplied that is determined by a cost-plus model. This means the gridcos’ transimission price will be determined by the overall cost of their investment plus a “reasonable” return. In this way, the government hopes to open up the distribution and wholesale markets to more competition while curtailing the gridcos’ ability to earn massive profits.

Consequently, the National Development and Reform Commission and its local branches will impose greater scrutiny on gridcos’ costs and will determine whether their reported cost figures comport with relevant regulations. Moreover, the current practice of cross subsidies for different voltage levels will be phased out for commercial and industrial end users as a competitively priced electricity market is gradually formed. The cross-subsidy for residential and agricultural end users will also be listed separately. This reform will first take place in a few pilots and is expected to scale up nationally.

Before power sector reforms, the retail/wholesale power market was controlled by the grid companies. To incentivize more market competition, this policy allows private capital to enter the wholesale and retail sector. There is no geographic restriction on where wholesale/retail firms can operate, which means this could lead to more regional competition.

Perhaps to entice private investors to enter this sector, setting up new utility companies no longer needs administrative approval, as long as the criteria specified in the policy are met. To ensure the continued availability and reliable of electricity, in the event that a utility company fails or exits the market, grid companies and dispatch network owner will still be responsible for ensuring power supply.

The proposed electricity exchange is intended to function as a platform on which power generators and retail/wholesale firms can directly buy and sell electricity. Previously, this function was controlled and operated by the grid companies (gridcos). So the creation of such an exchange is further aimed at eroding gridcos’ dominance by making this part of the business more independent.

The platform will provide related services such as information disclosure and trading account settlements. Two national-level exchanges will be set up in Beijing and Guangzhou, and multiple provincial-level trading hubs will also be built.

This action marks another improvement in the natural gas pricing regime as the price can now exceed the benchmark. Moreover, within the next two to three years, the government will accelerate the process for market-determined gas pricing by having all large quantity trades of non-residential gas take place at the Shanghai Petroleum & Gas Exchange.

Such an exchange serves as a national trading platform for energy products, such as natural gas, liquefied petroleum gas, and oil, and it will replace the current fragmented regional natural gas markets. In this way, the spot price formed at the exchange will better reflect national supply and demand conditions.

In addition to reinforcing pricing reforms, the five-year plan mainly focuses on improving energy efficiency and reducing emissions in the power sector. To meet these objectives, the plan calls for raising the share of electricity use in China’s total energy consumption, because electricity is considered more efficient and less polluting than other forms of energy consumption, such as fossil fuels for transport.

But because China’s power sector is predominantly coal-based, to achieve less pollution while consuming more electricity requires strict mandates on coal power plants efficiency. On the residential side, the plan also calls for coal boilers to be gradually replaced by central heating systems. In terms of transport, the government is encouraging the construction of more charging stations to incentivize the use of electric vehicles.

The plan projects that by 2020, China’s electricity consumption will reach 6,800 TWh, which translates into an estimated 4% to 5% annual growth, slightly lower than the growth rate during the past decade. To align with the macro energy target of having 15% total energy consumption come from non-fossil fuels, the deployment of hydro, wind, solar, nuclear, and biofuels will be prioritized in power sector development.

Meanwhile, coal power generation capacity will be capped at 1,100 GW by 2020, a moderate increase from 900 GW in 2016. However, given the trend of declining coal power utilization, the increase in actual power generation will be smaller than what the headline growth in plant capacity implies.

Finally, emphasis is also placed on improving grid reliability and load balancing capabilities. To tackle demand disparities throughout the day, the government will continue promoting demand response projects, such as time-of-use prices, smart grids, and distributed power. For cross-regional dispatch, such as the enormous west-to-east electricity transmission project, the plan supports building new ultra-high voltage lines to boost transmission capacity.

China’s power market has long been controlled by the state-owned grid operators. Prior to this reform, state grid companies (gridcos) controlled both the retail and wholesale electricity as well as power transmission and distribution (T&D). This status quo meant that the gridcos effectively monopolized the power sector, and most of their profits came from the price differential between buying from power generators and selling to end users.

What made gridcos even more profitable was that unlike in other countries, power generators couldn’t raise prices on their own based on market conditions or peak demand periods. That meant generators often lost money but gridcos’ bottom line was largely unaffected. In effect, this created an inflexible and unresponsive power pricing system.

The most significant aspect of this plan, then, is allowing end users to directly purchase electricity from power generators, a breakthrough of sorts after more than a decade of gridlock that stalled power sector reforms. That’s because previously, the Chinese government set the on-grid tariff—the price at which the grid bought electricity from power generators—and also controlled end user prices. For instance, industrial end users actually saw their electricity cost drop as a result of this reform, suggesting previously they were paying an artificially higher and uncompetitive electricity price.

This plan also calls for the T&D price to be determined by a “cost-plus” model, which means, in principle, the gridcos will be confined to electricity transmission and will no longer be involved in the power wholesale and retail market. In short, transmission and distribution are being separated.

Consequently, electricity prices will be gradually determined by the market, and new electricity exchanges will be established to facilitate competitive pricing. Finally, private capital will be allowed to enter all segments of the power sector, including in T&D. Whether private players will actually invest in this area remains an outstanding question because of high upfront investment and the lingering political clout of incumbent gridcos.

The indirect effect of this reform will be to gradually chip away at the gridcos’ monopolistic position, which has severely hampered market competition. That this reform plan was jointly issued by the CCP Central Committee implies that it required considerable political backing to get it passed.

With this move, natural gas prices are being further liberalized. Not only is the previous upper ceiling on gas price removed, large industrial users can now directly negotiate the price of natural gas with suppliers without government intervention.

Moreover, while natural gas used for agricultural purposes, particularly for fertilizer production, is still priced below market, the price differential has been reduced—meaning the government is cutting back price subsidies for agricultural consumers. The intent is for fertilizer producers to eventually pay market price for natural gas.

Finally, as expected, the 2013 natural gas price reform now applies to all non-residential gas consumers. This means that consumers that were allowed to pay below market price during the grace period can no longer do so.

Previously, only NOCs were allowed to import crude, which in turn sold the oil to private refiners. This policy, however, specifies that any oil refiner that has a capacity of over 2 million tons/year and meets certain efficiency and pollution standards can apply for their own crude import quota, effectively ending NOCs’ monopoly on crude imports. Moreover, refiners that use more advanced technology or have overseas subsidiaries that produce crude will be prioritized in receiving an import quota.

As of April 2017, 22 private refiners had already acquired crude importing quotas totaling nearly 82 million tons (1.64 million barrels/day), making up 12% of China’s total crude oil imports. This uptick in imports prompted the National Development and Reform Commission to announce that it is no longer accepting new applications for crude import quotas, citing concerns about domestic refining overcapacity.

Under this formula, the price of non-residential gas can now freely fluctuate up to 120% of the benchmark city-gate price. The benchmark price itself will be determined based on the weighted average of the prices of liquefied petroleum gas and fuel oil, which are both close substitutes for natural gas, to mitigate unfair pricing behaviors.

The new pricing formula won’t be retroactively enacted to ensure a smooth transition. This means Chinese consumers can still purchase gas at a lower price for now, as long as their consumption remains below 2012 levels. But the new pricing formula will be phased in gradually to cover all types of natural gas consumption, including LNG, shale, coalbed methane, and synthetic natural gas.