Ok Jose, once again for those unwilling to read the above referenced articles:

To implement an open de-regulated free market for electricity (etc), it is necessary to enable ALL customers equal access to all suppliers (unlike current pseudo-free-market systems where only a privileged few very large industrials or retailers are allowed to purchase in the LMP market). The "problem" (excuse for this restriction) of high transaction costs for generation / suppliers is eliminated by requiring each customer to pay at a flat rate for the cost of an intelligent robot agent to interact in the market for them, and for the cost of operating the central database system where their purchases are assigned to suppliers, and billings and collections are automatically invoiced and payments recorded.

1) Each customer pays a flat rate of $5.50 / month which covers the cost of i) a new intelligent meter ii) its communication system to the central market database. iii) the cost of operating the central database. iv) purchasing and retiring the existing old analog meters from the distribution entity. The basic unit includes a simple display / keypad terminal mounted inside the premises, and capability to communicate securely with a web browser on the customer's computer. For an added cost, the customer may purchase more elaborate in-premises terminals from the distributor or third party companies.

2) Each (single phase) meter integrates a first motorized local disconnect which can be remotely controlled by the distribution entity to deal with moves / non-payments, and by the customer to handle premises isolation if desired, e.g. for anti-islanding of local generation during a power outage. Comparable control contacts are provided for larger customers.

3) Each (single phase) meter provides to optionally integrate one or more motorized local disconnects in sub-bases which can provide to connect and separately meter either or both local CHP generation and / or one or more PHEV grid-wise electric vehicles. PHEV's are required to include a capability to communicate via power-line carrier with the controller in the meter to identify the paying customer for purchases and to manage re-sales back to the grid. Simpler meters are available to act as parking meters / charging points for business and large public parking lots.

4) Each (single phase) meter includes a premises energy management controller which can communicate, ideally via secure local powerline carrier or wireless lan, with intelligent appliances, thermostats or control plug-ins to use to manage loads during peaks when prices in the market exceed the payer's thresholds, to try to keep the local load curve most economically in line with the pre-purchased options profile, and to implement appropriate responses to ISO / Market Manager broadcast emergency requests. Standards bodies must accelerate efforts to improve communications protocols from controllers to appliances to define what messages are to be exchanged and their meanings.

5) The central market makes available for all reliable next-day weather forecasts for temperature, insolation and precipitation.

f) Local distribution entities become simple geographical pipes-and-wires monopolies, areas assigned by regulators, operation under regulation, with their allowed costs+ per connection point and per unit of product delivered set as today in rate cases based on current well-known formulae.

6) Generation and transmission entities of any size and source become unregulated free enterprises all with equal access to any market they may choose to compete in. The smallest grid-connected solar system of grid-wise PHEV can compete equally to sell into the market at the same price and to the same customers, if they wish, as any large generating entity. Alternatively they might petition the market manager to set up a separate category of "renewable energy" in which only accredited renewable sources can compete and they may be able to get a higher price from ecologically committed customers.

7) All generation transactions are public information, freely accessed by anyone. (customer consumption data only in summary). This is then available for entities considering installing new generation, and for watchdog groups or auditors looking for instances of abuse of market power etc.

8) Customers interact with the market as described in the Part 2 article referenced above. In summary it amounts to purchasing one day in advance "options to consume by category, 15 minute periods" at 50% of the final price of the category. At time of option expiry, the customer may choose to consume the power contracted and pay the other 50% or relinquish the option. Payments for unconsumed options are collected by the market manager and applied to reducing payments for consumed options. Creative market managers may also work out rules/methods to allow advance trading of these options prior to closure.

9) All market interactions can be carried out automatically by the basic programming delivered to the customer in the initial meter installation. If customers choose not to put any settings into the meter initially, it simply observes their typical load profile and does the best it can to accurately predict their next-day load profile based on day-of-week, weather forecasts and recent changes which might indicate guests, vacations etc. Creative third party companies are free to sell to customers better and more advanced meter programs and other options, but all customers are required to purchase from the central market, to keep in place the maximum incentive for peak-load-leveling and to avoid the "free-rider" problem.

10 ) Market geographic areas are set up according to the needs identified by state / provincial regulators, who should probably become the board of directors of the market manager. Markets are organized hierarchically, with areas larger than states operating their own regional markets in which smaller markets etc. may participate as customers. Customers may only participate in the one market to which they are assigned by the regulators / market managers, but generation entities are free to participate in any or many markets at any level they choose.
11 ) Legislators, when setting up this system, should consider establishing an entity which can act as contractor-of-last-resort whose mandate is to monitor and project several years into the future the region's load development, generation mix, etc. and, if provably beneficial to all customers, have the authority to make long-term contracts for new-build generation to guarantee no shortages on the system which would allow absolute unsheddable demand to exceed supply. They would then become responsible to market their contracted purchases into local or neighboring markets or failing that, to asses a clearly identified tax on market transactions to meet the contract payments. This process must be understood to be an absolute last resort action ideally never used, and is only provided to avoid the alternative of economy-crippling shortages (e.g. California), or especially an event of private enterprise encountering an inability to finance large baseload generation in advance of it's entire output being saleable into the market, resulting in less-ideal builds of inefficient plants fueled by vanishing fuels such as natural gas.

12) Other issues can be addressed by reading the articles, or by posting questions here.

also with respect to the merchant generating entities to:
b) eliminate/minimize the need for "spinning reserve" by providing the ISO the ability to quickly and dramatically manage load on a per-feeder basis by broadcasting emergency "for payment" consumption reduction / auxiliary generation startup requests, responses to which are easily reconciled in the market database by identifying and rewarding (with fees charged to the failing entity, generation or transmission, which caused the emergency) those customers who under-consume their pre-purchased options in the emergency period.
c) perhaps also work out a means to handle VAR correction where and when required, esp. with the inverters used by small solar customers which are technically capable of generating at any arbitrary power factor on demand.

Jeff Presley
9.10.07    Jose,

I never said the site was perfect, just an interesting viewpoint to how to solve your impasse. Both you and Len feel you have the best approach, but the fact is, no one will let either of you implement your scheme. in the REAL world. So it would be wise to simulate it and see how the simulations come out.

The bad news for almost all "change orders" to electricity per the GenCo, TransCo, DisCo and MarkCo model is that the entrenched provider isn't recompensed for their stranded generation capacity, transmission capacity, distribution capacity etc. Therefore your panacea of letting MarkCo solve the world's problems never gets to happen, because of those Billions that have been spent building up the 1st three.

Deregulation doesn't work because the monopoly rightfully asks the regulators for something in the kitty to pay them back for all that stranded plant. Right away, there is a thumb on the scale as the butcher weighs out that meat..

What all this has to do with the title of this article escapes me now.. :)

Joseph Rosenthal
9.4.07    Jose Antonio,

I have a hard time finding European electricity prices (I know how to find U.S. prices well), but here is what the folks at power engineering recently came up with for 2007 electricity prices in Europe (in U.S. cents per kwh):

Denmark 22.89 Italy 15.74 Germany 13.16 Netherlands 12.62 Belgium 11.43 UK 11.16 Spain 10.35 France 8.54 Finland 6.95 Sweden 6.60

Now, I understand from our mutual friend Fred Banks that Sweden, Finland and France are all heavily invested in nuclear, though he has lamented that Sweden has squandered this advantage.

For comparison's sake, Power Engineering lists the U.S. average as 9.28. That is because of the smart places that rely on central station power run by a utility, and not because of the dumb places that expected something called the "market" to build their power plants and give them a bunch of fancy meters and whiz bang renewables.

Electricity is or should not be a playground for anyone's theories and notions. It is a service essential to modern life. We know a way to provide that service at reasonable rates--central station power. If you are not concerned about the environment, use coal to provide that power. If you are concerned about the environment, use nuclear to provide that power (and yes, build some reserves, apparently they're not too costly or else France would be choking from them.)

The burden of proof is on anyone else if they think they have come up with something better, and I'm not interested in Connecticut being the guinea pig. We've suffered enough from theories and platitudes.

Don G: Further, re: problems with existing vertical monopoly systems... e) there is no way for individual customers to distinguish among themselves their reliability requirement, which results in the regulators enforcing on everyone the costs of providing the reliability demanded by the most vocal, usually a tiny minirity. Under IMEUC plan, you can identify e.g. a small part of your consumption to require 99.97% reliability (your main floor lighting, a refrigerator) for which you pay an appropriate premium. For all the remaining consumption (balance of lighting, cooking, climate control etc.) you can assign it to a much lower reliability category at a lower cost, say perhaps 75% reliability, which means that MOST OF THE TIME you are free to run it as you choose, but IF the market manager requests, you will only operate it on a 75% cycle in any 15 minute period. By this means, the ISO is able to eliminate spinning reserve and other similar costs, which is where the lower price is based. Different customers will have different requirements among these categories, according to economic circumstances, particular events (mother-in-law visiting) etc. f) there is no competitive free market discipline imposed on monopoly operators of generation and transmission, results in over-staffing, high rates of waste in operations, gold-plating of facilities (incentives are to increase costs in order to win rate increases).

many others.

Another interesting feature I would like to see integrated into this system is a capability for the meter and the ISO / distribution entity via each meter to EITHER send emails to the owner / customer's designated email address stored in the meter by the customer and changeable as desired, OR perhaps optionally to send broadcast outage information via text messages to cell phones etc. of groups of customers OR make provision for whatever future media may become useful. Emails would be useful when no-one is home due to working or travelling to inform of exceptions (under temperature conditions, appliance failures, power failures, local generator status, out-of-tolerance price spikes etc.) while broadcasts from eg. ISO or distribution would be useful for keeping all customers up-to-date on outages / predicted returns of service etc. Initial estimates could be based on automated sniffing of the SCADA data, with later refinements provided by work crew managers as more detailed information comes available.

Providing the service would cost little to nothing extra with the IMEUC infrastructure in place.

http://www.physorg.com/news9778.html

Here is an interesting potential addition to the development of IMEUC. "Penn State engineers have shown that a white-LED system for lighting and high data-rate indoor wireless communications, coupled with broadband over either medium- or low-voltage power line grids (BPL), can offer transmission capacities that exceed DSL or cable and are more secure than RF."

The concept is that White LED's used for lighting, when powered by an electrical network e.g. house wiring, wiring in commercial spaces which carries BPL signals, will themselves broadcast that signal in the light they produce. This enables wireless data delivery at bit rates up to 1 gigabit-per-second to any illuminated terminal configured to receive the signals. A very interesting concept, though not directly related to energy management / peak load management. Perhaps it points the way to future auxiliary revenue streams.

Just a bit of further reinforcement of the above discussion of data storage costs:

"Building on Philips long consumer electronics heritage, the revolutionary new drive features an ultra-fast eSATA interface that is six times quicker than the industry-standard USB 2.0, giving users immediate, additional capacity to store more of their music, movies and photos than ever before.

The SPD5130 hard drive has a pioneering single-disk form, allowing for significantly smaller dimensions than the double-drive solutions currently on the market. It will be available to buy in Europe and the US in the summer, priced at 449 EUR and 499 USD."

http://www.physorg.com/news100351474.html

My first "estimate" calculation above was based on a unit storage cost of $200 / 250 gig, or $0.08 / gig . This Philips hard drive includes power supply and high-speed buffered serial data interface for $0.05 / gig. Result is the customers may have not quintuple the absolute storage required / year for $0.01 each, but eight times the absolute storage required. Data storage is a non-issue.

http://www.caiso.com/docs/2004/09/17/2004091712202...

Here's an excellent primer for anyone interested in how current electricity markets work (and don't work).

Just a few clarifications Jim:

1a) The Market Manager is not in any way a regulator. Their only interaction is to own and operate the metering and market system, contract for the billing service, collect and distribute payments for provision of energy.
1b) No "sweetheart deals" as now happen under "retailer de-regulation" because of the market rule which states "every customer must purchase from the market to which they are assigned".

2) I presume you mean for new services in difficult locations. IMEUC says nothing to help. It would be Jim's responsibility to arrange and pay for any infrastructure required for his new service. I see no reason all closely-built attractive customers should subsidize Jim's country mansion.

3a) In IMEUC no-one is already forcing these companies to service unprofitable users. All customers in a market region are subject to the same market. There is built-in provision for pre-payment terms, e.g. "pay-first-then-use", as used to be in Britain with coin-operated meters, for deadbeats with the remote-disconnectable meter and communications capabilities.
3b) Re- overbuild in a region, that is entirely up to the capital markets. Ideally open market-based access to all transmission could enable temporary justified overbuild to sell into neighboring markets until local consumption re-economizes a build. However, given the approach of PHEV's switching a large portion of transport fuel onto generation (which could double present demand) I see this as not a serious issue.

4a) I think you err in your estimation. When most existing utilities are generating e.g. 90% of their power with long-paid-off baseload assets which can put out for e.g. $0.03 / kwh, transmission and distribution total cost (at least here in Ontario) adds about $0.04, and residential rates are $0.11, I think everyone's doing quite well. For your area, find out what the large industrial rate is, assume 1/3 of that pays T&D, so assume that large generation is pleased to produce for 2/3 of the industrial rate. Add $0.04 to that for residential distribution costs, and compare it with your actual bill. Are they loosing money? Probably the peakers are if they're not owned by a large baseload, so whoever creates the peaks is creating the problems. That's largely commercial offices, single-shift industrial, and residential A/C.
4b) The big point of IMEUC is it eliminates peaks, flattening the load curve out so the extremely costly (per unit energy) peakers are eliminated. It does this by i) enabling integration of grid-wise PHEV ii) rewarding fairly customers who can shift loads from peak periods to off-peak periods. Whereas under any other market, such well-known technology as making ice in storage at night and shutting down the refrigeration during day peaks is simply not justified because there's little or no difference between night and day electric rates, under IMEUC with a real-time rate, when it comes time to start up that gas-turbine peaker and the rate jumps from $0.07 to $25.00, you WILL very quickly discover who can most economically shift loads off-peak. It will require some adjustment time, and some additional build of high-efficiency baseload generation, but it will happen, and quickly. Eventually the load curve should completely flatten, with the price settling to a point just a bit above present off-peak rates (due to the need to pay off about a 25% new build of baseload generation).
4c) The other point of IMEUC is to eliminate the haggling over "how much wind etc. generation can the grid handle"? With good demand management at every customer, wind can run full whenever the wind blows, solar can generate whenever the sun shines, and customer systems will be pre-organized to exploit the opportunistic availability of excess generation whenever it happens.

5) You're right, IMEUC largely concentrates on bringing the smaller customers into the market, which to now has been the exclusive preserve of the largest industrials. It's an equality thing as much as anything.

6) I believe you're wrong about what proportion of electricity consumption could be "in play". It will certainly take a little time to get the controls, thermal and vehicle battery storage, smart appliances, home CHP engine/generators etc. etc. etc. systems in place, and that needs to be considered, but without the market, the others are seriously handicapped, which is a dumb thing for our society to have happen especially with the present world petroleum situation.

Len

Len,

Regarding #2:

No, I didn't mean new construction. I meant marginal areas that are unprofitable to service, and are only serviced because the regulated electrical utility is forced to do so. I think a similar issue arises with the Postal Service, which has some routes which are extremely expensive to service, but overall they can make money delivering mail. (The same could be said about health care in the U.S.).

An example might be a rural setting, very little power sold to several homes on a long transmission line - so lots of maintenance for little return. You really have two options: 1) Make the utility service it (i.e., make them subsidize the cost of maintenance) or 2) Make the customer pay their higher access rate (i.e. maintenance on many miles of transmission line that services very few people).

Another issue regarding #1

If a small A utility can produce 100 MW at 10 cents, and a larger utility B produces 900 MW at 20 cents, then everyone will want power from the smaller utility. But if the 1000 MW worth of demand, how is this decided? Do customers bid up? Do you have a dutch auction or whatever and everyone buys 10% from A and 90% from B? This is how a single large user (such as a factory) might buy up all the cheaper power, perhaps by agreeing to certain conditions that smaller user would not. It would seem that cherry-picking deals might still be finessed through the system (via a quantity-discount arrangement, which most providers and some customers may insist on having).

"In the realm of application of economics, the area is replete with the challenges of developing incentives in all relevant aspects of electricity market operations and planning. The market design area truly constitutes an unparalleled opportunity for power system engineers and economists to contribute to the effective design of the future electricity industry."

This is a quote from the paper

"Evolving Nature of Electricity Market Design in the U.S.
G.Gross
University of Illinois at Urbana-Champaign"

http://www.pserc.wisc.edu/ecow/get/publicatio/2004...

I heartily agree with his assesment, and encourage knowledgeable technical people to begin getting involved in discussions.

Adrian: "There is a big difference between smart consumption meters and smart DG meters. Whilst the former are actively managed, they are primarily processing, sending and receiving data which does not have to be dealt with instantaneously. " -- I'm not sure this is a valid objection. It has been my concept (needs proving) that all control signals from grid management to the DG crowds can be broadcast signals, e.g. single send to all in an area, no confirmation messagegrams, to which the meters would be programmed to respond with the appropriate action (raise the voltage, improve the power factor, etc.) Ideally each message requesting an action would be accompanied by a market price which the grid operator would be willing to pay for the action, and the DG's response would be dependent on price and local circumstance.
I've also been thinking about your other objection, that local voltage control will be difficult with a large proportion of grid power being supplied by eg. small residential DG units. That is a given, IF the installation of them is uneven, e.g. a high concentration of them in a given neighbourhood wanting to feed excess power out to other neighbourhoods. The problem is that, if say 27,600 volts on a substation bus is capable of supplying a 5 mile long 100 amp 3 phase feeder to a neighpourhood with e.g. 17,000 amps at 234 volts with a 2% voltage drop, then the neighbourhood's 34,000 amps peak of DG units get active and try to feed 17,000 amps excess power back into the substation, then they must raise the local voltage in the neighbourhood by at least 4% (in order to compensate for the 2% drop which customers were seeing on the power coming in + the 2% drop they encounter feeding back out). That 4% increase in voltage will be perceived locally as a voltage change from 234 volts to 243.4 volts which might become a difficulty. The 2.1% increase required to feed just a small excess back into the grid is likely very acceptable without any action and would cover almost all neighbourhoods.

I see sevaral mitigating factors. a) That voltage change is a worst-case extreme event, not likely to happen in many locales and in fact quite acceptable even if nothing is done about it. It could become significantly more problematic with a simgle large DG unit at the end of a long feeder but that's not really the condition we're discussing, and can be handled by requiring the large single unit to singal the substation for a tap-change every time he starts up. b) If a particular neighbourhood begins to approach these conditions then the distribution grid operator needs simply to install directional sensors on their substation transformers and adjust their tap-changing logic to handle the case. c) Worst case, a program can be set up to regularly take instantaneous sums of meter readings for all meters identified to be on particularly sensitive feeders in the central database once every 5 minutes. Substation actions (tap changes) can then be made based on sum of current flows with reasonable expectation of accuracy. d) It is also obvious to have the communicating meters record local voltage as well as wattage centrally, and have a program at the central database scan a small representative sample of neighbourhood voltages to determine if tap-changing actions are required at given substations.

The only significant change in control strategy required is that the voltage management mechanism needs to be designed to expect bi-directional power flows, whereas they presently likely only deal with single-direction flows. The tap-change required to fix an over-voltage condition for a customer is opposite if the customer's feeder is flowing power out than it would be if the feeder is flowing power in. It's just a minor upgrade in controls, however, and not likely required very often, especially for the first ten years or so.

Also, regarding your last: "Finally, regarding a flat charge for paying for the grid. I have seen this issue addressed in the past, and each time the politicians have shied away from mandating it; flat charging impinges disproportionately on the poor, whereas apportioning grid charges to each unit of power sold means that the rich subsidise the poor "
The separation of distribution from generation, transmission and (retail if used) into a regulated monopoly on geographic boundaries should be considered an absolute requirement for competitive electrical systems. Otherwise the liklihood of the distribution owner making mischief for his competitor generators or retailers is just too much, and too difficult to monitor. I think your fears of problems are far over-emphasized. Here in Ontario we did it with no complaining at all anywhere (at least on that score) The province now has about 90 separate regulated distribution companies mostly private, some rural co-op. There is also now a fair bit of consolidation going on among them, which makes sense. Britain also. It works very well. The cross-subsidy thing is a red herring, I'd think.

I would also point out that the 100 tenants of a single-meter apartment building are probably subsidizing the distribution of the McMansion suburban estates, not the other way around.

The following are selected comments from the postings to EnergyPulse article "10 More Ways to Become a Third World Utility", 10.24.08, by Jim Burke, Executive Advisor, Quanta Technology

at http://www.energypulse.net/centers/article/article...


Dick Maclay 11.4.08

Len, as was the case in natural gas regulation the devil is in the details any time regulators or politicians get involved. So when they mess up some of your principles things can go very wrong. Worse yet regulators do not learn from their mistakes in a timely manner. So while I find the core principles of your proposals attractive, I continue to believe we need to implement them in a manner that will allow a market to evolve without depending on regulators to get anything right. Just setting up generation and distribution as you suggest requires more than we can expect from regulators, so the best hope is that the wires businesses will evolve over time in response to market forces. Far from perfect but the best I believe we can expect. So we differ primarily in our expectations regarding regulators.


Len Gould 11.4.08

Dick: The way I am seeing IMEUC implemented has no dependence on any regulators whatever. Because the system changes required are so broad, it will need to be implemented by legislation of the political entity with authority, eg. state or national government depending on a country's constitution. The legislation must be drafted to conform to the goals I've stated above. The same legislation then makes the present "regulator" bodies simply the board of directors of the Market Manager entity, with the responsibilities and authorities described in the defining documents.