How do you sell electricity?

Factual Questions
1

Because of the current situation in California (pun intended), I have found a gap in my knowledge. Perhaps someone could fill it?

How does a state get power from another? I mean, I realize the power grid is interconnected, but how do they know where the juice goes? My power bill is easy- the current flows down their wires to me. But on the grid, Company A sends their power to Company B; in a few months, they could be reversed; yet it’s all on the grid together. How do they know whose is whose?

CNN reported a mysterious company in Washington supplied additional power. How? Extension cords stretched across Oregon? (And I heard they may be getting some from Canada as well- how can they cross the border, do they have to declare it at Customs?)

Ah jest don’t unnerstan!

2

My understanding is that there is this thing called a Grid and the Grid is where power is “dumped into” or “pulled out of”. I know it crosses state lines and I would presume our neighbors to the north would have access to it also. It allows power to be “shared” among a huge geographically dispersed group of people. For example, a hydro plant in Washington generates power and if the market conditions make it conducive could add power to the Grid on any given day. In reality it contracts with companies like PG&E to provide a certain amount of power, at a certain price, at a certain time.

PG&E, on the other hand, has to deliver power to us so they are always pulling power off the Grid. The amount they need varies based on the time of day, day of the week etc. (Remember, power is extremely perishable… it can’t be stored). Now PG&E buys power from producers and it is delivered onto the Grid. It doesn’t matter exactly what power is really there at any given time… but if PG&E buys 100 MegaWatts from someone there is presumably a way to show that the producer delivered that amount of power to the Grid.

The problem in California right now is that both PG&E and SoCal Edison are defaulting on their payments and the producers don’t want to sell them power anymore… or only at some outragous price. The gov wants to provide assurances to the producers that they will get paid and that should stabilize the markets.

3

Here’s an earlier thread on the same question, with so-so replies, and here’s a better thread, with a reply by Anthracite that was so succinct it stopped the thread :slight_smile:

Arjuna34

4

BTW, in California I think that anybody… and I mean anybody, can be a power producer. Assuming you could get your local community to allow it you could erect a tower and place a wind generator on top of it and start producing power (people have actually done it) and any excess power you produced could be sent to the grid and PG&E would have to pay you a fair price for it. There is a special kind of meter that could measure how much energy you put on the Grid. Many companies actually do this now… I think it’s called co-generation.

5

I’m pretty sure this is true, and according to the Time/Life book I was just flipping through (Energy Alternatives, 1982):

Don’t know if that’s still the case (as the book is nearly 20 years old) but I’ve been checking into sites such as http://www.homepower.com which has various examples of people using alternative power sources and some are indeed selling back to the power company. They have a section on “Solar Guerrillas” who are people using solar power without going through the hassle of getting permits, etc, and as a result they aren’t able to sell back energy (one guy claims you have to buy a special meter, and then pay a special meter reading fee, (which sounds highly likely!) so it’s not worth it for him.)

I’m thinking: If I were to do something like this, would PG&E have to pay me the same rates they’re paying from the outside sources? Seems like you could almost turn a profit if you were in an especially sunny or windy area, lol.

6

Wind power would be self-generation, and before deregulation it would have required a contract with the IOU (Investor Owned Utility.) Wind power kind of shows up when it shows up, so it is tough to schedule, and therefore tough to know how much it’s worth, making it pretty much useless as a generation resource.
Cogen, or Co-generation, is a generator that also uses it’s waste heat to displace burning another fuel. Industrial processes that use lots of electricity but also use a lot of low grade gas heat (like dairies, laundries, etc.)can make cogen work, but most other efforts have shown it to be less than cost effective, particularly with the current high cost of natural gas. The CEC (California Energy Commission) paid for cogen in a whole mess of high schools locally, and they pulled them out after a few years in most cases. The waste heat was to be used to heat the swimming pools, which offset natural gas use, and the electricity was to be used for whatever. The problem was that the pools only needed to be heated for a few months in the winter, and electricity was cheap in the winter, when natural gas is expensive, so it ended up costing them more than before, plus some maintenance headaches.
This mysterious company could have found that based on the outrageous prices the generators are selling power to the utilities at made it cost effective for them to stop using the heat and electricity from it’s cogen plant, and instead shut it’s own process down and just sell the power to California. $30/MWh is at least 5 times what it would cost them to generate it, even if they threw away the waste heat entirely.

7

Yes, a thread-stopper for sure!

You know, I did a search before I posted, but neither one of these threads showed up. Hmm…

8

I believe that the rate that PG&E (for example) would have to pay you for your excess electricity is set by the PUC and isn’t subject to the wild fluctuations in the market we are seeing currently. I also don’t think you could make much money doing this unless you had a huge wind farm like you see on the hills around the SF Bay Area… and in that case a big part of the equation was a energy tax deduction which meant they were sometimes just write-offs and not really interested in generating a profit anyway!

9

dolphinboy, sure there was such a setup on the news yesterday. A woman bought a solar power system for her house in Calofornia & when there is extra electricity (a minus reading on the reader) its sent back to the electric company and she gets credit. These systems are $20,000 to $90000 though.

10

I used to work in the power industry and actually dealt with some of these issues. I changed fields in '92 and so my information is dated from that time but this is how we handled it then.

First, to answer the OP, Anthracite is correct. The electric grids of the various utilities are (for the most part) connected to each other. When utility A is generating excess power and utility B needs it, utility B can simply pull the needed power from utility A’s grid. Most utilities have agreements in place with each other involving how much they pay for the power and how much they are allowed to pull and they simply check the meters each month and figure out how much who owes who.

More interesting is when utility A and utility C have a power sharing agreement and they have no connection to each other. If each are connected to utility B then utility A can provide power to B and B provides the same amount of power to C. C pays A for the power and pays B a certain amount for the transfer. (This is called “wheeling” and the charge is the “wheeling rate”.)

The one place where I disagree with Anthracite is that my understanding is that the two grids are not simply connected together. There are substations where the grids connect and the connection can be broken. This is partially to prevent massive blackouts like those in the northeast in the '60s and '70s and partially to prevent a drain on your grid during peak demand periods from demand on your neighbor’s grid. This may be a regional thing though; I’m mostly familiar with the situation in the southeast.

As for cogeneration, the term as we used it applied to any “non-utility” provider of power. Mostly, these were as Engineer Don described. Here in Georgia, for example, the Georgia-Pacific paper mills are big cogenerators. Paper mills generate a lot of steam as part of their normal operations and GP uses the steam to run generators to power their own plants. Any excess power they can sell back to the utility (Georgia Power, in this case).

Now, large cogenerators like GP usually have their own agreements with the utilities. (They also have to coordinate with the utility when they cut their generators on or off because of the demand they place on the grid when they aren’t generating on their own.) But (as of 1992 anyway) anyone who was producing power on their own could provide it to the utility and the utility had to accept the power and pay them for it. (We called everyone who wasn’t us a cogenerator, even though the term wasn’t strictly correct.)

This lead to the appearance of “cogeneration utilities”. Small companies with a windmill farm or whatever who generated power and sold it to the utility. There were also a number of individuals who had their own solar panels or windmills who sold their power to the utility.

The amount the utility paid in the absence of any other agreement was the “avoided cost” of the power being provided. This works this way. In general, the higher the demand the more it costs the utility to generate each additional kilowatt. Utilities have what they call “base load” units which run all the time. These are usually fairly cheap to operate. As demand rises, more and more units have to be brought on-line. Obviously the utility tries to use the cheaper units first. When electricity demand reaches its highest point the highest cost units are being brought on-line. Things like combustion turbines which are very fast to start up and shut down but are also very expensive to operate. (You don’t want me to start going into minimum runtime/downtime calculations, do you?)

The Avoided Cost is determined by how much it would have cost the utility to generate a kilowatt of electricity itself at the same time the cogenerator is supplying it. So, the amount the cogenerator gets is determined by when the power is provided. This doesn’t help the smaller and individual cogenerators since when demand (and therefore price) is the highest they are probably using their power for themselves and when they have power available to sell the avoided cost will most probably be lower.

You do have to have special equipment to connect your generator to the grid. (Your generator has to be properly synchronized to the rest of the grid or else you will be pulling power out of the grid and probably burn your generator up.) There are also fairly tight tolerances on how “clean” your power can be. (Proper voltage, frequence, etc.) Most small/individual cogenerators don’t find it cost effective to bother trying to sell their power back to the utility.

11

In the UK every supplier meters its power to the grid, both in and out.

All consumers have their power metered too.Some large consumers have their own generation capacity and the nature of their operations mean that they cannot easily change how much they produce(such as steel mills or large CHPS plats).They have import/export meters installed.

Power suppliers will guaruntee to supply their consumers using the network which makes a charge based on the power transfer.

The power suppliers will have several points of generation and will generally use the cheaper ones first and as demand rises the cost of generation rises.

Suppliers will buy power from a wholesale pool, as the demand rises then the cost of generation rises so the pool price rises.

Some generators have sophisticated monitoring systems that automatically bring in their additional generation sets when the prices per unit becomes viable.

Consumers agree to various tariffs, they will agree to a peak demand price and if they exceed this they pay for the extra power at a premium.The monitoring equipment has a needle that moves to the peak position and stays there and until reset once every month or quarter.This means that one minutes worth of excess demand can cost a consumer a month or more of peak demand penalty.

By limiting the peak demand of consumers in this way suppliers can gear up for a baseline generation capacity more efficiently without having to buy as much power from the pool which is usually more expensive than their own capacity.

Consumers will also pay for maximum capacity, lets say a consumer uses say 10MW but needs security of supply, like in a hospital, then the consumer will pay an extra fee in case they suddenly need more power for a short time - bit like an electrical overdraft facility.This means that the network supplying the hospital has an installed capacity of maybe 20MW and that costs more money to maintain and more capital investment.

Consumers will also pay for priority supply, again imagine a hospital, where the supplier will guaruntee supply.This matters when cascade failures occur, a fault may develop in the network somewhere which sucks in power from all over, this sudden overload causes the nearest generators to cut out, reducing capacity to supply and placing a greater burden on the other generators, which in turn shut down and so on.The fault may last only a fraction of a second but it can be enough to start a cascade shutdown.
To counter this the network has load shedding equipment which will cut off users in a strict priority basis.

Consumers will be penalised for their load characteristics through the use of power factor metering.This is not easy to explain but basically some users have plant that ends up using more capacity than the power that is actually consumed, so although they use 10MW of power they utilise 15MW of generation and network capacity.This encourages consumers to manage the characteristics of the consumption.

Sometimes it is worth it for the supplier to buy say 50MW of power from a relatively expensive source rather than run a 600MW generator at only a fraction of its capacity so you can see unusual peaks and troughs in the pool price.If that demand went up by another 200MW the pool price might actually fall as the more efficient 600MW unit is brought on line and the supplier wants to load it up to its best operating point.

There is much much more but I think I’ve illustrated how complex the electrical generation market can be.

12

“In the UK every supplier meters its power to the grid, both in and out.”

It’s pretty expensive there. My friend in London paid about 200pds for electricity in January. My friend in California paid Green Mountain energy $280 for electricity in January.
There was a woman in California who just got a statement for more than $12,900 & they corrected it to $300.00, for one month, which she said she could handle. But I couldn’t.

13

Just a nitpick, windfarms etc. are not Co-generators but are what are known as “Qualifying Facilities”. Co-generators basically require the production of electricity as a by-product of whatever the main production process may be. QFs are broader, indicating that they “Qualify” for special rates, and that their energy must be taken by the Utilities. Historically the rate paid for energy to QFs was much higher then the going market rate. This is linked to the history of why they were developed. Basically, back in the late 70’s early 80’s when oil prices were through the roof there was talk of $100/barrell oil. So the regulators wanted to encourage more diversified and cleaner power. So based on forecasts of the high price of oil these QF rates were established that were quite high. Well oil prices did not go to $100/barrel, instead they collapsed, but the rate paid to QFs pretty much stayed the same - pretty high.

I guess this is off the OP a bit, but just wanted to add that.

14

Rules have changed here in California. The reason people assumed all generators other than the utility were called “CoGenerators” was utilites were required to enter into contracts with QFs (Qualifing Facilites) at the value of the avoided cost of their most expensive generation. To be a QF, you had to have a efficiency of above 42.5%, and to do that you needed to use the waste heat (i.e. cogen) or to be wind or solar or something. These power contracts were greatly increasing the costs to consumers, because the average avoided costs of the California utilites was in the range of 2.5 cents per kWh, but the highest, from the peaking units, was about 13 cents. When we were flush with energy in the late 80’s and early 90’s, the rules changed and with new QF’s the contracts only required the utilities to pay new QF’s the average avoided costs for power provided at different times, but still had contracts with the old QF’s to pay the max. A big part of the reason California rates were so high was these old QF contracts. Oddly enough, they were also the source of “cheap” energy for the last 8 months or so, being only 13 cents instead of 15 to 30 cents, or more than a dollar at some times, whereas the newer QF’s avoided selling back anything, since the cost of natural gas was so high they would lose money on any power sold.

Anyhow, since deregulation, the avoided costs of generation are determined by the power pool, and IIRC any new generators selling power into California get use it. I believe this includes anyone selling from out of state who doesn’t have a sell back contract with their local utility. When sizing cogen units, it is best to size them for the lowest of your electric load or heat load. If a company has a minimum continuous usage of 10 MW, and their heat load only supports an 8 MW generator, then they won’t usually have a sell-back contract, because they never sell back. They do have to have apropriate meters and switch gear, just in case, but no agreed purchase price for the power thy sell back. In the recent months they might have had the opportunity to cut their own production and make money with their generation facilites.

15

BTW, besides Anthracite’s good summary, here is another “Electricity for Dummies” :slight_smile: at MSNBC:

And about QFs. It is pretty complicated, QFs get a rate based on indices connected to the price of Natural Gas. So when the price of NG spiked so did the rate they recieved. Considering that a lot of them had long-term contracts for NG well below the indexed rate, they were making a killing.

On the other hand some did not have the long-term contracts and were indeed having to pay for expensive NG and then having to decide if it was economical to run or not.

16

Total hijack but when I saw this thread title, all I could think was this:

[Seinfeld soup nazi]
No juice for you!!
[/Seinfeld soup nazi]