During the energy crisis after the Russian invasion of Ukraine, a few small power companies (is that what you mean by retail providers?) had a hard time because they had sold one or even more years fix price contracts to consumers, and had not bought enough on a fixed price contract themselves. They had been prepared for some risk, but not for such a major upheaval. One or two went under, and their customers had to move to now much more expensive contracts from other power companies. The regulator has since then imposed more demanding risk management and liquidity norms.
I think what you describe is like what in the US is called "retail choice." In the US it is allowed or not allowed state by state. Originally the US had "vertically integrated" electric utilities. They were encouraged to divide the business into 1. generator owners, 2. transmission owners with bulk wholesale substations, 3 balancing authorities RTO/ISO, energy market operators 4. distribution utilities with substations and wires to homes and businesses. Later retail choice added 5. retail power marketers using the wires of 2, (3) and 4.
They do exactly what you say, they buy in the market, maintain large cash deposits in their bank, sell the power to the homes and businesses, bill them for the energy, and pay the transmission and distribution costs.
In Texas, about 10% of retail choice change plans to get sign up deals, very similar to how people change cell phone plans. Personally and professionally I don't support retail choice and studies have not shown long term cost savings to the customer. To me it is a risk game for the retail choice company. Others may disagree.
The sad thing was and is that precisely people on the lowest incomes often live in the worst insulated homes, and hence faced the steepest bills. So the government stepped in and gave (all) households an energy subsidy, and even though that addressed the short term hardship, it is not a long term solution. It is too expensive, and removes some of the incentive to save energy, and has since been abandoned. So now the local housing associations that own a lot of the cheap rental housing are rapidly insulating their housing stock, helped by some government subsidies. That is certainly a better way to subsidize the solution to a problem that will not go away.
In the Northwest US we have a large nonprofit generator, transmission owner, and balancing authority Bonneville Power Administration (BPA) with about 28GW+ nameplate generation. In 1980 a friend of mine wrote the NW Energy Act. It requires BPA to do a 20 year IRP forecast every 5 years, and when adding generation, calculate the equivalent efficiency to the proposed generation, and give efficiency a 10% premium in cost over adding new generation.
As for price information, if you have a dynamic price contract, you get advance pricing information, and you can already use that to charge your car if you have a smart charger. Currently protocols are being developed to do the same for household appliances and heating systems, using price input from the electricity supplier and data from your solar panels. Technically none of this is very difficult, but it demands a lot of coordination and supervision from the regulator, given our competitve energy market. In the end, it is all about creating a fully transparent competitive market, because that is the most efficient system.
Agree...but. There are many articles and meetings on price formation in the US RTO/ISO system which require approval from FERC - the central government agency. In the US, electricity is sold roughly 3 ways. 1. Power Purchase Agreements which are private contracts between the generator and the customer. They are often 10 years, and they are not public. They are common for renewables generators and large sophisticated customers: data centers, casinos, and industrial customers. 2. Private bilateral contracts days ahead to real time. It is similar to any commodities trading and happens on platforms like the Intercontinental Exchange. 3. Organized public markets like RTO/ISO and ISO-lite EIM markets.
the way 3 works, and I believe Europe does this too, is that the generators bid in the lowest price they will sell a 5, 15, or 60 minute block of MWh at a certain time. The MWh offers are sorted from low to high. The balancing authority goes up the offer curve from low to high until it adds up enough MWh to meet the load forecast. Then it sends a dispatch signal in software to the generators, and watches them run individually to ensure they deliver.
Say 10 wind plants bid in at minus 1 penny per KWH, 20 solar plants bid in at 2 cents per KWH, some combined cycle natural gas plants which need to run continuously bid in between 3-4 cents per KWH, a coal plant which has to run continuously bids in at 4 cents per KWH, a nuclear plant has to run continuously bids in at 5, and several short term peakers bid in at 10 - 15 cents per KWH. This particular scheduling block goes up the offer curve until 11 cents. That is the price formation process.
All generators will then be paid 11 cents per KWH. They are not paid what they offered which was the target price to meet their capital costs, people operation costs, and fuel costs for fueled generators. Over the year the high price points dominate the total cost summed over the year.
If you take all the hours in a year and sort them from the highest energy price to the lowest, you get the price duration curve.
Anything you can do to lower the demand on the left side reduces overall costs for the year. Sometimes 80% of your costs are in 20% of your hours of the year.
I would like to see more power flowing through PPAs at lower than peak prices.
In the US it is recommended housing be 30% of income, and energy - dwelling heating and cooling, electricity and natural gas or bottled gas be, 3%. Above 3% is termed energy burdened.