Purposes of the Market
There are four main purposes of this market design.
- To provide equal access for all connected suppliers to all connected customers in a fair and equitable manner. Note that “all suppliers” would include even the smallest residential CHP generator or PV installation.
- To present reliable price signals to customers reflecting real delivery-time related costs of suppliers to provide their commodity, and to provide useful indications of these price signals sufficiently far in advance of the actual supply to allow the customer an opportunity to make an alternate choice, such as reducing their purchases in the period or starting up their own generating units.
- To assemble efficient dispatch commands for provider entities sufficiently far in time in advance of the requirement to enable especially larger generating entities to operate their equipment in the most profitable manner possible within the market criteria.
- To produce clear price signals of business opportunities available within the region covered such as areas with transmission congestion or with rapid load growth supporting new generation etc.
Operation of the Market
The most basic operation of the market is to:
- Resell to customers the electricity or natural gas produced by large baseload suppliers under very long-term fixed price contracts negotiated by the Market Manager entity based on their projections of future demand.
- Provide means for merchant generators of all sizes to contract with customer load in excess of this baseload to provide additional power in excess of the baseload.
The Market Manager uses a public tender process to add to this baseload contract supply as load increases within their market territory. Ideally they never get themselves into a position of having to pay for more production than customers purchase, but in the event that happens they are still responsible for paying the contract, so must try to re-sell the excess into other neighboring markets. Failing that, the Market Manager must add a levy onto all market transactions to collect the amount necessary to cover the shortfall amount owed the provider above the amount collected by sales. The reason for this provision is to enable provider businesses to finance large and costly investments in for example nuclear generating stations, gasification plants, transmission lines (wire or pipe) or overseas LNG installations at the lowest possible risk on capital, and therefore the lowest cost of interest and thus of power or gas delivered. Conversely, the provider is responsible for providing 100% reliability on these baseload contracts, so must themselves organize alternative sources of supply during any station outages planned or unplanned, whether that amounts to purchasing from other suppliers or paying the Market Manager to organize sufficient emergency load reductions and/or previously undispatched backup supply to survive the outage, and also paying the alternate supplier. The contracts will include a sufficient penalty amount due to the Market Manager for outages which must be handled by the Market Manager. The contracts may also include financial penalties due to either side for other events, such as unplanned load rejection events. Each generating entity and customer also declares their optimal operating power factor for generation and load, and the price required to provide additional VAR correction if available.
The Market Manager is also responsible for recording into the market database at least two hours prior to the end of each day an accurate prediction of the following day’s weather conditions on an hourly or quarter-hourly basis, including outdoor temperature, wind conditions, humidity, precipitation, insolation, sunrise and set times.
Market Managers are set up in a hierarchical structure with the smallest entity being individual municipalities, the next level up being regional ISO’s, and possibly another one or two levels up having national or continent-wide coverage. Each level market manager is free to do transactions in any other market at any other level they wish, but there can be no physical mixing of market customers and a customer may belong to only one market. Which market a customer participates in is determined by their physical connection to the transmission or distribution system. In general, the structure established for markets will closely resemble present distribution entities.
Price Categories are separated by “relationship characteristics” between suppliers and customers. I use the term “reliable” here to mean what maximum percentage of any predefined interval the market manager is allowed to signal the customer’s meter to disconnect the load, at the market manager’s discretion. For electricity, these might be set up as:
- B100 99.999% reliable supply from the baseload mix of prime energy sources outside of peak hours
- B75 75% reliable supply from the baseload mix of prime energy sources outside of peak hours.
- B50 50% reliable supply from the baseload mix of prime energy sources outside of peak hours.
- P100 99.999% reliable supply from normal peaking fuel mix from 11:00AM to 6:00PM on business days
- P75 75% reliable supply from normal peaking fuel mix from 11:00AM to 6:00PM on business days
- P50 50% reliable supply from normal peaking fuel mix from 11:00AM to 6:00PM on business days
- W30 30% reliable supply from wind generation when available
- S75 75% reliable supply from central solar generation/thermal storage when available, baseload mix when unavailable.
- S40 40% reliable supply from any solar generation when available, from 8:00 AM to 6:00 PM, hours adjusted seasonally.
- RB100 99.999% reliable supply from an available mix of certified renewable prime energy sources outside of peak hours
- RB75 75% reliable supply from an available mix of certified renewable prime energy sources outside of peak hours.
- RB50 50% reliable supply from an available mix of certified renewable prime energy sources outside of peak hours.
The default category assigned for any customer consumption in excess of their previous estimate would be B100 or P100, depending on time of use. The default category assigned for any supplier deliveries in excess of the planned dispatch orders would be the highest active price in the market for any category for which the supply is qualified until all consumption of the qualified category is fulfilled, then the same logic for lower priced categories. For example if a homeowner’s natural gas fueled CHP unit was originally dispatched to provide 30 kwhr from 11:00 AM to 5:00 PM but had actually provided 35 kwhr due to it’s response to an open request broadcast from the market manager, and the distribution losses averaged 3% from that area to the point of delivery declared in the market manager’s broadcast, then that address would be credited in the central database with 30 kwhr at for example P100 if that’s what the original dispatch had been, plus 5 kwhr at P75 assuming that’s the open request broadcast to which it had responded. There is then placed into that account a charge for 0.9 kw at P100 and 0.15 kw at P75 for the amount of energy lost in distribution and not re-sold by the market to customers.
Of course market managers will soon learn which categories they need to have set up in order to optimize their system for its individual local characteristics. There appears to be no reason to restrict the number of defined categories, for example if finer separations of base and peak reliability and timing would help customers to move more loads into the shedable categories then they should make those available.
The way customers then make purchases is by programming their meter to automatically:
- Predict their preliminary estimated average and peak demand within each relevant price category for each 15 minute interval of the following day before the start of the day.
- Record those predictions into the central market related to the meter identifier.
- Predict how much excess generating capacity the customer site might have available for sale into the market in each 15 minute interval, and offer that for sale into the market at the customer’s preset price.
- Transmission and distribution entities also predict their line losses, transformer losses, VAR demand and unmetered supply contract requirements such as streetlighting, and record these as planned purchases along with all other predicted purchases. (At the end of the day they are billed for net in minus net out at the average sell rate of each of the relevant providers.)
- There then follows one or more half-hour rounds of opportunities for customers to make adjustments to their predicted loads based on the supplier’s bid price outcome for each price category within the market.
By the end of day a few minutes before midnight, the Market Manager’s central software has completed final most economical dispatch orders for every offer made in the database including those not accepted, which information is made available to all concerned in the central database. The price for each category is set by calculating the predicted base demand for a period for each category, then accumulating sufficient generation to satisfy that category from among all offers of supply starting with the lowest priced offer until the predicted demand is met. Generation which the Market Manager has pre-contracted is selected first until completely assigned, then alternative suppliers are selected on a lowest price first basis. The highest price selected is then taken as the selling price for all supplies within that price category, with the proviso that the sell price within their own market for the Market Manager’s fixed contracts can never fall below the cost price to the Market Manager.
- The Market Manager then in cooperation with the ISO prepares requirements for spinning reserve, standby and VAR correction, which should take into consideration the Market Managers ability to command load reductions of lower-reliability loads and to broadcast emergency offers to purchase additional generation. There then follows one round of bidding on the supply of these requirements by all qualified generation with reserve available. Managers of buildings with emergency standby generators would be logical participants here.
Then, during the following day the meter measures and records the customer’s net consumption in each 15 minute period, their peak 1 minute interval, and their average power factor. If the power factor is outside a range pre-set by the market manager then their values are adjusted accordingly. These are then compared to their previously recorded purchase plan. If their consumption exactly matched their estimates in each category, then their account is charged only the estimated amounts. If over then the excess is charged at the highest reliability rate in effect at the time depending on whether a Market Manager load reduction command had been in effect in the period. If under the customer is charged for ½ the difference at the consumption rate they had estimated.
For example assume three customers had estimated 4 kw P100 and 8 kw P50 for a 15 minute period on peak when the market manager determined that total load was close to exceeding their planned dispatch and had issued a command for low-reliability loads to back down to their minimum. If the first customer’s consumption matched the estimate exactly (2 kwhr with a 12 kw peak) then they are charged 4 x 15/60 = 1 kwhr at P100 rate and 8 x 7.5/60 = 1 kwhr at P50 rate. If the second customer’s consumption was 8 kw for 7.5 min and 12 kw for 7.5 min and the meter recorded 3 kwhr with a 12 kw peak then they are charged 2 kwhr at P100 rate and 1 kwhr at P50 rate. If the third customer’s consumption averaged 4 kw for all 15 min and the meter recorded 1 kwhr with a 4 kw peak then they are charged 1 kwhr at P100 rate plus 1/2 kwhr at P50 rate as a penalty for overestimation error (50% of the error), which penalty is collected by the market manager. This penalty is necessary to avoid customers simply always overestimating consumption in order to avoid ever being bumped up to the high-peak P100 rate. (Perhaps some mathematicians and economists could be contracted to come up with a more effective incentive system). From these penalty amounts collected the market manager pays their costs of operation, while excess amounts are credited back to all customers to proportionately reduce the rates according to consumption, with the first priority being the low-reliability categories. It would be a decision for elected legislators to determine how this rebate system actually operates in any particular market, ideally based on scientifically logical societal goals and not simple political pressure. In this way, the market manager’s incentive is to encourage customers to always consume less than they estimated so the market manager can access the under-usage penalty collections, and the customer’s incentive is to keep their estimates as accurate as possible and to keep as much of their on peak consumption as possible in the low reliability rate categories in order to benefit from the rate reductions resulting from the inevitable overestimation penalty rebates. In net, each customer, despite regularly being assessed penalties, would still achieve the lowest cost energy possible by using this system and the better they can manage and predict their usage the lower their costs will be.
Each meter would be installed with an included free software algorithm capable of doing a decent job of interacting with this market without customer intervention for persons not interested in dealing with the meter themselves. It would be able to estimate customer loads based on previous accumulated history and available weather predictions, and could automatically control new appliances (refrigerators, laundry, furnaces, water heaters, air conditioners etc) built with an included standard powerline carrier or wireless network interface, and with plug-in relay blocks designed to control older appliances not having the control capacity built in, similar to current BSR-X10 relays. There should also be available for customer purchase a range of more or less sophisticated user interfaces, ranging from a few led indicator lights to low-power unlighted LCD touch-screen displays and on to full interaction with a customer’s personal computer network.
The non-technical hurdles to implementation of this system in any particular geographic area (state, province, country) are not trivial but also not insurmountable. It appears that:
- no constitutional changes would be required in most countries I am familiar with
- some legislation would be needed to
- authorize and fund setting up the Market Manager initially
- fund the staged purchase and installation of the equipment and retirement of the present distributor-owned electric meters.
- authorize and fund if necessary each of the long-term baseload purchase contracts individually at the outset and ongoing as required (this is also one way that public policy may be implemented, such as wind, solar, other renewables generation subsidies etc) If needed, single items of legislation may grant this authority for limited times and limited amounts to the Market Manager to avoid every solar PV or WTG install requiring separate legislation
- explicitly bar the Market from discriminating among suppliers on any ground except perhaps some externalities criteria set by legislation such as fuel source, environmental effects, supply security (LNG)
- if prudent, enable the Market Manager to organize access to natural gas storage to enable them to always accept delivery on their long-term contracts even at times when consumption may be very low
- explicitly bar the Market from making payments to consumers for providing “energy efficiency credits”, known as negawatts. I anticipate instead the development of a large market for companies specializing in energy efficiency selling their expertise on an annual contract basis with perhaps an upfront fee to automate some loads in customer sites, installing a CHP unit or PV array, then managing the meter program remotely via internet for the year. They might even consider taking over payment of the meter charges for a flat rate, in a guaranteed rate contract system between themselves and the customer.
- many regulations will need to be changed, such as
- moving dispatch planning to the Market Manager
- moving responsibility for grid reliability planning to the Market Manager
- adding a public audit function to metering and billing data collection
- self-insuring or brokering any new liabilities.
- It shouldn’t be necessary to worry about the large number of new IP addresses required for the meters to communicate as part of the existing web given the new IP V6, though for security reasons it may be wiser to separate the meters onto a new local network.
- Many others
Undoubtedly there are many aspects of this market system which would benefit from the input of professional engineering and economics experts. However to this point I haven’t seen any insurmountable obstacles to the realization of this system provided meter development and manufacturing were done to a rigid set of interface standards by several competing companies with large volume sales commitments. Consider the potential for them, of changing 100 million meters in North America in a five year period. The least used functions of the meter, such as generator connection and anti-islanding, should be designed as accessories which are only plugged into the meter and electronically sealed by an authorized market representative if the customer purchases the appropriate plug-in parts. It may also develop that market managers could become stuck holding excessive long-term supply contracts which might need to be bought out if a technology breakthrough were to occur in for example photovoltaic equipment or CHP generation, but this risk is not worse under this system than the same risk under any alternative scenario, including the status quo.
The overall resulting benefits of implementation will be well worth the effort. Present industry participants can anticipate having much more streamlined decision-making processes in an equitable open and minimally regulated market. Present regulation authorities will find, in switching to being market managers, that their tasks are clarified and simplified, while they will no longer be open targets for every influence peddler or self-appointed savior of society. Customers of all sizes will be able to participate in the market on an equitable basis to maximize their outcome by simply accepting the market’s defaults, making a long-term fixed-price contract with an outside party which could provide a range of services from remotely custom-programming their meter to offering long-term hedging, managing their purchases themselves, or building up their own provisioning facilities such as generation, storage or perhaps even local interconnection across lot lines as economics and safety regulations would dictate.
And finally, at every point the incentive vectors are pointed in a direction to allow market forces to provide maximum net benefit to society as a whole.