By Juan Rios on 21/12/2021
Topics: emission trading, Energy Transition, deregulation
It’s been a lively year in terms of power and climate policy in China as the country’s policymakers strive to set the framework necessary to achieve China’s emission reduction targets. In 2020, President Xi Jinping announced that China intends to become carbon neutral by 2060 and reach peak carbon by 2030. Although decades away, there’s significant work yet to be done.
China is the world’s largest greenhouse gas (GHG) emitter, accounting for 27% of carbon emissions globally. The country relies heavily on coal, and more recently natural gas, to power its population and heavy industries. It even overtook Japan and became the world’s largest LNG importer in 2021. China is the world’s largest consumer and investor in renewable energy sources. It boasts a generation capacity of 579GW as of 2019 data, which is close to 3 times the total capacity of capacity in the USA.
From the above, its clear that achieving China’s set targets will be no walk in the park. But if any nation could achieve such a dramatic shift in their energy mix and policies, it must be China.
The country was the first to emerge out of the initial wave of COVID-19 in early 2021 and industry demand was quick to ramp up. A couple of months later, as the rest of the world caught up and emerged out of lockdowns, demand for fossil fuels globally quickly outstripped supply. Now, countries in Europe and Asia are facing unprecedented energy crises as coal, LNG, and subsequently power prices soar to record highs. Nations around the world are facing difficult challenges with regards to energy security, particularly as the northern hemisphere enters the winter period and LNG supplies continue to tighten.
China experienced the full weight of its energy crisis in early October. High coal prices internationally and domestically, weather related issues at critical coal-mining provinces, environmental regulation crackdowns and, perhaps most importantly, caps on provincial energy consumption also known as ‘dual control’ policies, meant the government had to curb power in most major provinces. We understood from our client base in China that plants were forced to shut down for several days, and even weeks, in the most affected provinces.
In the midst of it all, as the country’s regulatory bodies sought a way out of the crisis, China’s top economic planner, the National Development and Reform Commission (NDRC), announced critical regulatory changes for the power sector. This mainly constituted changes to the pricing of coal-fired power and the partial deregulation of the retail electricity market for large consumers above 10kV. From an outsider’s perspective, the power shortage certainly had some influence in these announcements, however, they weren’t the only major announcements made by China in 2021. Below, we point out some of China’s most recent power and carbon regulation changes and their implications for large energy users. They include:
China’s National ETS was launched in July 2021 for the power sector. Its launch was delayed due to COVID, but its mechanics were derived from the experience gained in several pilot schemes across seven provinces. Given that it only concerns the power sector for the near future, this will be a topic for another blog post down the track.
As of today, there is no specific timeline for the expansion to heavy industry, but there’s been indications that all eight major polluting sectors (power, petrochemical, chemical, building materials, iron and steel, nonferrous metals, paper production, and aviation) will be included by 2025. For more information on China’s ETS, ICAP has a great overview. Alternative, please watch our webinar on China´s ETS we ran last year for more details.
Number of entities, by province, participating in China’s national ETS in 2021
Source: Carbon Brief analysis based on MEE (2020) and public information. Chart by Carbon Brief using Highcharts
The deregulation of the Chinese power sector has been an important objective for policymakers, but there weren’t any clear indications of what the next steps would be or a timeline for implementation. That uncertainty is now partially cleared up with new regulations published by the NRDC on the 15 October.
According to the NDRC, as of 1 December 2021, all commercial and industrial (C&I) users will have to buy electricity in the wholesale market in provinces where there are power trading exchanges[1]. These markets will be run at a provincial level and mean that the regulated tariffs are abolished. From December onwards, in most major provinces, market prices will be determined monthly for the month ahead based on the weighted average of the monthly wholesale electricity price in each province.
Purchase of electricity will be done via direct participation through the exchange or via suppliers. If power consumers have not identified a power supplier via an open market channel, they will continue to purchase power from the State Grid during the transition period at the monthly average price. Regarding the price of electricity, the State Grid must give the power users at least one month’s notice before switching from the regulated tariffs to the wholesale rates. If a user is already trading in the open market but needs to go back to the State Grid for last-resort power supply, they will be penalized by having to pay 50% more for that same power.
Regarding the prices themselves, we understand that the local exchanges will announce the weighted average monthly prices via online and offline channels (such as business halls) three days in advance for the following month.
In terms of procurement options, we are already seeing offers in various provinces where suppliers offer alternative forms of purchasing methods, such as the option to fix a portion of consumption at a fixed rate and leave the rest floating on the monthly wholesale average.
This new method of purchasing electricity also means that rates are now unbundled. Whereas regulated tariffs were bundled and included all grid costs, rates in China’s major provinces are now clearly defined and will consist of:
Electricity price = purchase price (through supplier or state grid) + transmission and distribution price + government funds and surcharges
where the purchase includes the monthly average electricity price + ancillary service fee + other fees
The above begs the question then, what option is better? Do you choose a power sales company or the State Grid to purchase your electricity? From the information we have until now, it is currently impossible to determine which option is better. One could argue that its better to trust the State Grid than any power sales company. This is because power sales companies will require you to sign new and potentially complex contracts: something E&C can help you navigate. In addition, under the State Grid there will be no ‘sales’ company fees. However, you could also argue that due to the new policy, power sales companies will eventually have more market power and will grow to be better over the long-term than the State Grid. They will have an incentive to diversify and improve services and, thanks to competition, the overall fees will be lower and the added benefit higher. This is the beauty of deregulation, where competition fosters innovation, lower costs, and better products.
One short- to medium-term impact of the end of the traditional fixed tariffs, is that the electricity price will become more cost-reflective and volatile. Unfortunately, C&I customers will have to become accustomed to volatile power prices. Over the medium- to long-term though, the liberalization and growing market competition will have a direct impact on the shape of the wholesale markets and the future of investment in generation. With the ability to choose, C&I customers will have more influence on the supply and pricing of power and the products that come out of these markets.
As part of the same announcement in October, China took a big step in power reform by mandating that all coal-fired power plants enter the wholesale market. Coal-fired power will still be priced at the base coal price plus a float range; however, the float range can now rise as much as 20% compared to the base price. Previously, price increases were capped at 10%. For energy-intensive industries, prices will not be subjected to the float cap, thus a +20% price increase is possible for this sector. This will incentivize them to optimize energy usage or invest in self-generation over the long-term.
According to the NRDC, the aim of this was to encourage coal power plants to generate more electricity and ease their profitability pressures in the short-term. Given the increase in fuel prices globally, and more specifically in China, it also allows coal-fired power prices to fluctuate in a wider range to better reflect market fundamentals. However, this does leave C&I consumers exposed to potentially higher wholesale electricity prices. According to data since October, this is already the case in most provinces where prices are close to the 20% limit. Prices in provinces including Shandong, Jiangsu, Guizhou, Anhui, Guangxi, and Liaoning, have already increased by close to 20% for non-energy intensive industries.
Over the long-term, coal power plants will find it challenging to compete as more renewables come into the market. The end of guaranteed operating hours for these power plants means that old and less efficient plants will struggle to keep up with price competition and eventually fall out of the dispatch merit order.
Before this was announced in early September, there was no guidance or set method on how to procure off-site renewable energy in China. The rooftop/on-site solar market had boomed for years, but there was no indication as to what the regulators were doing for the off-site renewable energy market. More importantly, not all companies were able to invest in rooftop systems.
In late 2020 and early 2021, things started to change with news coming out of a couple of peer-to-peer (P2P) trades between power trading centres and large manufacturers. Clearly, the appetite for renewable energy was there, and the role of certified ‘green’ electricity was becoming more and more prominent.
It all changed in September 2021 with the first green power trading pilot in China. Out of the 31 provinces in China, 17 participated with a volume of 7,9TWh and a final premium of 3 to 5 cents/kWh compared to the regulated tariffs. We understand that of the invited entities in this first pilot, some companies signed 3–5-year deals with renewable energy developers.
For C&I customers interested in this market, it is necessary to enter the deregulated market first via the power exchanges. It will then be possible to interact with renewable energy developers directly and negotiate a rate. For now, it’s unclear if these bilateral trades can be conducted directly or during a set period. It is also unclear how this will connect – if at all – to the national ETS and when there will be a secondary market for green certificates. For this product, customers who contract with renewable energy developers will receive one Chinese Green energy certificate for every MWh of generation. As the market matures, it’s likely that power sales companies involved in the deregulated market will come out with ‘green’ power packages as part of their offers and simplify the whole process.
So, as you can see, China’s policymakers have had a busy 2021. All these new regulations represent a significant step in China’s power sector deregulation journey. More importantly, in the long-term they will have important knock-on effects for China’s road to decarbonization.
