Due to your great reputation in the industry of energy markets, Iran Electricity Market (IREMA) would be very pleased if you could answer the following questions. The questions are designed to clear the issue for the worldwide and IREMA audiences.
If we categorize the trading environment to spot markets, centrally managed future and forward markets (power exchange), and the bilateral contracts:
- Within the electricity market that you are currently engaged with/you have conducted research about,
- Should the parties that trades based on the bilateral contracts frame work go through procedures of the power exchange for bilateral trading or they could make it completely independent?
It is absolutely up to the market participants to decide. In terms of whether or not they have the option to trade through bilateral contracts or power exchanges (Nordpool, Epex, …) they are totally provided with this flexibility to go through either and there is no obligatory regulation to require them behave in favor of one. It is by any means their discretion to decide.
- Could you compare the volume of trades in the power exchange and the bilateral contracts with respect to the total supplied load?
As in all electricity markets around the globe, market participants in England can trade electricity through bilateral contracts, power exchanges or the spot/balancing market. The majority of the energy is traded bilaterally in advance. Bilateral contracts and power exchanges constitute up to and sometimes above 70% of the total “energy consumption/generation”. I am afraid I cannot break down the volume more though the share of bilateral contract in this mix is to some extent higher than power exchanges. The point is, the role of the energy and power exchanges is note solely offering direct trade platforms. They provide financial facilities and tools for energy businesses to help them hedge bilateral or spot commitments. It is these financial mechanisms where they show their advantages.
As you are aware of, the topology of the transmission lines is considered in the day ahead markets enabling the market operator to simulate the closest economic efficiency in the real-time. In such cases:
- If the transmission system experiences a failure that will not be cleared in long term (with respect to the day-ahead market time scopes):
- Some power plants that may earn profit due in no small part to this failure. How these kinds of power plants would be treated?
- Some power plants that may lose their opportunity to sell their energy due in no small part to this failure. How these kinds of power plants would be treated?
- The consumer side may also be imposed with higher electricity prices. How they will be compensated against this happening?
- Are there any penalizing/remuneration mechanisms to incentivize TSOs reduce the outage time?
- Is there any insurance mechanism to compensate the generation/ consumption side against the transmission system outages?
In GB balancing arrangements, the market participants’ generation or demand are evaluated against their commitments. Day ahead trades are not tied with the network topology and constraints though balancing mechanisms are. All trades’ data, regardless of the trading type, whether it’s been through bilateral, exchanges, etc. are fed into the balancing arrangements. The market participants are obliged to stick to the volumes they have contracted for in advance. If they deviate from their commitments they are exposed to the System Price, i.e. the price of balancing the system for System Operator. This could be a negative or a positive price. Along with the contracts volume that are fed into the system, the System Operator (SO) also receives Bid/Offer prices from market participants prior to the settlement period (which is half an hour in England). These are prices market participants are willing to pay or get paid should the SO asks them to deviate from their contracted volume. At the end of the day, the settlement system uses the contracted volumes, the metered volumes and the Bid/Offer used by SO, to determine the system price.
If a market participant has been deviated from their commitment in a settlement period, they must pay or get paid the system price (per MWh of the deviation). If deviations were to maintain the system security, i.e. the SO asksed them to increase/decrease their generation/consumption, they are considered “SO-flagged” actions and are exempt from system price.
Electricity market encountered with inherent challenges of non-convexities resulted from the stop-start costs, minimum power generation constraints and on-off status of the generation units. Due to these non-convexities, the prices were derived with some assumptions and it requires a great attention to the cost recovery and market efficiency characteristics of the electricity market design to be preserved under these assumptions.
- How the non-convexities of the market clearing problem (such as start-stop costs) are handled in the electricity markets you have engaged with?
- from the optimization problem and driving the prices point of view
- from the payments point of view and cost recovery issues
As far as I have understood the balancing mechanism in England, these are factors assumed in the business analysis by market participants. They use these as input factors in their analysis whether it is to estimate the economical price for their bilateral/exchange contracts or to determine their Bid/Offer pairs to submit to the SO.
In England, SO uses Bids/Offers to estimate the cost of balancing the system which is cost of instructing the market participants to change the energy volume they are generating/consuming.
In many electricity markets, when the market operator wants to monitor the bidding behavior of the generation side, the designated market power detection procedures is based on diagnosing the Marginal Cost (MC) of generation. In the light of knowing this matter:
- How the market operator/regulator treats with the issue of MC detection?
- Is it acceptable/implementable to legislate regulations to enforce the generation side disclosing the MC for the market operator or it should be the market operator that drive the MCs independently?
- In hydroelectric power plants how the cost of water resources is considered in the calculations of the Marginal Cost of generation?
As far as I know, the SO does not monitor the MC of the market participants.
- What are the major differences between the electricity trading arrangements in Iran and GB?
I would say the major difference between the two markets are in the way they are governed. The basics of power system and market operations are almost the same all around the world. The difference lies in their governance attitude not in the software or hardware they use or even the methodology used for example to solve a mixed-integer non-linear program. As a few examples I can highlight the most important ones here:
A set of industry experts are evaluated against specific skills, experiences and criteria and form a panel who then monitor the efficiency of the electricity market arrangements. Almost all market rules and regulations must be approved by this panel before implementation. All panel members are from businesses active in the energy sector. The government representative(s) attend the panel meetings but have no voting rights. The panel meet each month for a whole working day (around 8 hours) to discuss a broad range of issues that need to be taken care of within the market and decide/approve the best solution.
Customer consultation is the core of all decisions in the electricity industry (not only electricity market) in England. The smallest decisions are not made without the industry being consulted as to whether or not they are happy with the arrangements which is going to be put in place. Market participants are frequently approached by the system regulator and system operator to share their opinion about a new project/plan or about a modification in the current procedures. They are asked openly to suggest their ideas if they are not content with the proposed methodology. You could not find even one new plan or modification going live without the industry being consulted and/or being invited to collaborate.
Depending on the depth and importance of the consulted on arrangements and/or modifications, the consultation period ranges from 5 working days to several months.
- Frequent Process Reviewing
All processes are subject to constant reviewing. This is explicitly stated once the process arrangements are approved by the panel. Similar to consultation period, how often a process should be reviewed differs depending on the depth and importance of the process which is determined by the material impact it might have on the electricity market participants.
- Supply market (retail market)
The electricity supply market was opened up to competition in England since 1998. There are hundreds of suppliers (retailers) who buy electricity from generators either bilaterally or through power exchanges or balancing market and sell to a broad range of energy consumers from households and commercial customers to large industrial businesses. Transmission and distribution companies maintain the power network as the vital infrastructure of the energy sector but they do not trade energy for profit. Energy consumers can easily choose which supplier to buy their energy from. To make this possible, as not all customers have their energy consumption metered on a half hourly basis, a robust and complex Supplier volume allocation process deploying accurate load profiles help settle the market every half hour.