Electricity markets material - UChicago...

Electricity markets material GEOS 24705 / ENST 24705 / ENSC21100

Copyright E. Moyer 2016

Electrical grid organiza/on and management: basic ques/ons

•  What controls how much power flows, and where? •  Who owns and manages what? •  How is electricity sold? •  Who pays, and to who? •  Who sets the amount that people pay? •  How big is the grid?

Electrical grid opera/on: basic ques/ons

From the Energy Informa0on Agency, U.S. Dept. of Energy.

•  What controls how much power flows, and where? Nothing except the balance of genera=on and demand – an en=re interconnected grid is a single complex circuit. Imagine a plumbing system with interconnected pipes but no “valves” that control the flow of current. You can’t control what power flows where except by =nkering with inputs and outputs

The U.S. grid is broken into 3 weakly connected regions, and not much power flows in between. But the regions are connected to Canada (strongly) & Mexico (weakly). Texas is its own grid! And its own regulatory en0ty.

For most of 20th century, one entity owned all components in chain Now typically owned by 2 or 3 diff. entities, managed by another, and market can be managed by outside broker – up to 5 players in game

Electrical grid: Who owns and manages what?

Image: Wikipedia

•  Generator •  Transmitter (long-dist. wires) •  Grid operator (wires operator)

•  Utility for distribution (local wires) •  Load-serving entity (seller to consumer)

Electrical grid: major regulatory shi:s

1.   UNIFYING AND CENTRALIZING GRID

2.   INTRODUCING MARKET FORCES

3.   DECENTRALIZING GENERATION


1.   UNIFYING AND CENTRALIZING GRID: shi: from disconnected organiza/ons and transmission to unified transmission (3 grid regions), gradually more centralized authority

•  1920: First regula=on under Federal Power Act (then

repeatedly amended over =me).

•  1965: blackout led to more communica=on between u=li=es on voluntary basis to ensure reliability

•  1977: Federal Electricity Regulatory Commission (FERC) established to regulate rates (+ license hydro), under authority of Federal Power Act

•  2005: Voluntary reliability council (NERC) replaced by an “Electric Reliability Organiza=on” with actual enforcement authority

1965 blackout was wakeup call New York City went dark, people were stuck in high-‐rises, crime spiked 2nd blackout in 1977 contributed to sense of system (and city) in decay

headlines, 1977 blackout

1965: bad relay setting caused line out of Niagara power station to shut down, overloads cascaded. Blackouts for 30M people: CT, MA, NH, NJ, NY, RI, PA, VT, + Ontario.

1977: lightning hit substation and lines, took out some breakers and power lines. Overloads cascaded, shutting down more lines. Blackout over New York City only, lasted all night.


2.   INTRODUCING MARKET FORCES: Transi/on from ver/cally integrated regional monopolies (one u=lity owns genera=on, transmission, distribu=on) to compe//ve systems

•  1992 Energy Policy Act: FERC can order a company to

carry power for someone else

•  FERC orders through 1996 encourage forma=on of Regional Transmission Organiza=ons (RTOs)

•  Most places now have compe==ve genera=on: u=lity or load-‐serving en=ty buys from mul=ple independent generators, with a market for power and hourly pricing

•  Possibly in the works: market system on retail side too (requires hourly pricing and so “smart meters”)

•  S=ll problema=c: compe==ve distribu=on


3.   DECENTRALIZING GENERATION: Encouragement of distributed power:

•  Energy Policy Act of 2005 requires net metering

•  Small (2-‐10 MW) operators can sell at market rate by Federal law

•  Demand-‐side management, or DSM (pay for “negawaa” genera=on) is now an op=on in some markets, areas

Summary of ownership in the new deregulated elect. industry

U/li/es are “wires” companies. They own the distribu=on and transmission lines, repair the lines, process billing, and take payment from retail customers.

RTOs are managers: (for most people, though not everywhere): They manage the market (buy and sell, set clearing prices), and exercise minute-‐by-‐minute control of genera=on and conges=on management (call to get plants turned on or off)

Anyone can be a generator: in market system power produc=on is open to all

Defini'on: Regional Transmission Organiza/on "An en=ty that is independent from all genera=on and power marke=ng interests and has exclusive responsibility for grid opera=ons, short-‐term reliability, and transmission service within a region.”

Regional Transmission Organiza/ons An RTO is an en=ty created to balance genera=on across a regional footprint regardless of ownership of genera=on ….invented to promote compe==on and hopefully efficiency. “Independent system operators” (ISOs) are similar to RTOs but ofen cover smaller geographic areas. RTOs eliminate the need for generators to contract with separate u=li=es to sell and transmit power, and prevent integrated u=li=es to favor their own genera=on and block transmission of compe=tors. The goal is to create a transparent market to incen=vize more op=mal building and dispatching of genera=on. In Europe analogous en==es opera=ng across countries are called “transmission system operators” (TSOs)

About 60% of U.S. electricity is managed by RTOs and ISOs

RTOs as of 2010 (ISO/RTO Council)

Note: Chicago area is part of PJM, not of MISO

RTO excep/ons:

Arizona: from electricity standpoint is essen=ally a colony of California – its genera=on not managed by RTO, but independent generators make long-‐term contracts with California, sell into California markets.

Texas: The only state where a single agency regulates both the genera=on/transmission side (wholesale prices) and demand side (retail rates). Texas is its own RTO, full state-‐wide authority. Makes planning much easier to have one central power.

SE U.S. is tradi=onal u=lity ownership and opera=on on big scales (e.g. TVA, The Southern Company) so no need for RTOs

Rocky Mtn. corridor doesn’t have much transmission

Ownership: high-‐voltage transmission

Generally owned by u=li=es but managed by RTOs (regional transmission organiza=ons). The RTOs are are themselves owned by groups of u=li=es.

Owned by u=li=es: 3170 total in U.S. (75% of customers are served by 239 investor-‐owned; the remainder are public, co-‐op, Federal)

The primary job of u=li=es (like ComEd) is to maintain a distribu=on network and to sell power to residen=al, commercial, and industrial customers. Many u=li=es s=ll generate much of the power they carry, but some generate none. The businesses of genera=ng and selling are becoming decoupled. You can even bypass the u=lity for your electricity purchase and ONLY pay them for the distribu=on service. Very analogous to phone system afer deregula=on.

Ownership: distribu/on

Genera=on can be owned by u=li=es but also by independent power producers who sell on the open market

Example: Exelon, who own Dresden nuclear genera=ng sta=on, is not a u=lity. It is mostly a power company that owns power plants and sells their output to u=li=es or RTOs. Exelon owns ComEd. The u=lity is a subsidiary of Exelon, not the other way around. When the lights go out, the guys (or gals) who come fix it will wear ComEd hardhats, not Exelon hardhats.

Ownership: genera/on

How is electricity sold? 3 markets for electricity genera=on

For electrical power itself

• Day-‐ahead market payment made under contract to provide power if needed at market-‐clearing price

• Real-‐=me market emergency purchases of power as needed minute by minute at pre-‐set rates

For electrical capacity

• Capacity markets payments made to all generators in RTO simply for exis=ng to provide backup (ca. 2% of elect. price)

RTO: Every day the RTO buys all the power that will be used and sells all that power.

Each day the RTO forecasts power demand for next day. Each day the generators all send in “bids” sta=ng how much they’ll be willing to sell their power for. The RTO then buys all the power it thinks will be needed, at the marginal price. I.e. everyone gets the price of the highest-‐priced seller whose power is bought.

But, the RTO doesn’t actually write a check to those generators =l the power is used. If power isn’t needed afer all, no $ change hands. Only if power is generated does the RTO writes a check to generators.

The RTO then turns around and sells all that power to u=li=es, who then sell it to their customers. The u=li=es write a check to the RTO.

Who pays, and to who?


U/li/es: The u=li=es pay the RTO.

U=li=es can also make “bilateral contracts” with par=cular generators, to lock in that power for the u=lity at a given price. If so, the u=lity then pays the generator just the difference between the market price and the contract price. This is a hedging strategy to minimize risk.




Generators: Sell to RTOs. Also get $ from contracts with u=li=es. Generators can also sell directly to customers IF on private land and if the distribu=on network can be bypassed.

And , generators are also paid not for power but simply for exis=ng, to provide power if necessary. (“Capacity” market)




Generators: Sell to RTOs.

Residen/al power customers: pay $ to the u=li=es




Generators: Sell to RTOs.

Residen/al power customers: pay $ to the u=li=es

Transmission owners: receive payment from the RTO, but just for recovering costs – fixed return on investment. (Need permission to build, though).

Note: If transmission owners are also generators they have insufficient incen=ve to build more transmission, since get more money for genera=on if it must be local because of conges=on. (Even 15% return w/ no risk from building transmission won’t outweigh the profit from genera=on).


Who sets the amounts that people pay?

In the old days

The u=li=es owned everything, and would charge customers enough to recover their costs. The state u=li=es commission would approve the rates.

Nowadays

Generator price set by the day-‐ahead market: Sets the hour by hour price that generators receive for power or for capacity.

Wholesale price set by market and by FERC: FERC sets the markup that the RTO can charge over market, and sets the fees paid for transmission.

Retail price set by state u/li/es commissions: The PUC sets the rates that the u=li=es can charge their customers. At present these are flat rates – no hourly charges – but that may change.

Usefulness of electricity market driven by 1) diurnal demand curve

.

Image: World Nuclear Org.

Usefulness of electricity market driven by 2) different opera=ng cost for different genera=on technologies

.

Market clearing means that everyone receives the price bid by the last (most expensive) generator whose bid is accepted. (Hourly bids). Nuclear will bid zero because it wants to be on always and its opera=ng costs are =ny. Oil is expensive so will bid high – will only turn on if price > opera=ng costs.

Pre-fracking-era supply stack: coal cheaper than gas

But, supply stack is changing drama/cally

.

•  What happens when gas becomes cheaper than non-‐dispatchable coal? •  When coal plants shut down? •  If bring on must-‐take no-‐marginal cost wind?

Peakers vs. baseload: In all previous history, the expensive marginal cost genera=on is fast to turn on and off, so can be used as peakers when demand is high

Peaker vs. baseload difference fundamental to market Generators are turned on when their bid is below market-‐clearing price

(Figure: Marson Energy)

Generators bid their marginal costs … then each generator receives the market-‐clearing price when it is turned on. (Even baseload gets the marginal price.) Should in theory result in incen=ves for building more efficient genera=ng capacity, also for clever peak-‐shaving strategies (demand reduc=on, storage, etc.)

Note: the market system does not guarantee that the user will get a lower price than in the old monopoly system. He now pays the marginal cost of electricity genera=on rather than the average cost. The marginal cost is always higher than the average cost, but the theory is that eventually retail prices will drop.

Old system: expensive peakers on only during max load

(figure from the U.K.?)

Baseload power stays on all the =me. High-‐marginal-‐cost power is purchased only during =mes of day when demand is highest. But how to manage now if the marginal genera0on is coal, which is not easily dispatchable?

Electricity strategies driven by the diurnal cycle

Peakers: buy high cost but fast turn-‐on genera=on that can come on just for the peak energy demand period. (Big complica0ons now that rela0ve costs are flipped.)

Peak-‐shaving: buy electricity when it’s cheap and store it, then sell it back to the grid when it’s expensive

Demand-‐side management: sign contracts with customers forcing them to turn off if demand is too high

Demand-‐side management: introduce =me-‐variable pricing for customers to incen=vize less use at peak periods, more off-‐peak

Load-‐dumping: since baseload power can’t turn off, some=mes just have to dump it if have too much

How big is the grid?

Total U.S. network: ~ 300,000 km Most of this is high-‐voltage

(> 250,000 km are > 230 kV) Cost of high-‐voltage on average $1M/km

Total value of the distribu'on part of the grid is of order $300 billion dollars.

Higher voltage lines carry more power (& tend to be longer)

Line length Mean length ~ 300 km in U.S. Prac=cal limits to transmission distance: DC ~ 7000 km DC, AC ~ 3-‐4000 km (Paris et al., 1984. Con0nental U.S. is ~ 4600 km east to west. Could transmit across the country, barely.) Longest individual HVDC lines > 1000 km (mostly in China, carrying > 3 GW each)

Line power Rated power ~ 1 GW in U.S. Check numbers: total 300,000 km at 300 km per à 1000 lines, each max ~ 1 GW. Total power ~ 1 TW. U.S. electrical use: 300 M people x 1.5 kW / person =

Transmission cost issues

... x 2 cost because of environmental issues (as with nuclear) Example: Arrowhead-‐Weston line in Minnesota cost > $1.1 M/ km in 2002. Original es0mate ~ $0.7M/ km; cost nearly doubled because of environmental safeguards, payments to landowners, permit delays

Note that high power means bigger / more expensive lines Rule of thumb = $500-‐700 /MW*km Projected total costs in future are high Es=mated new builds to meet rising electricity demand: $9-‐12 B/yr (Report Card for America’s Infrastructure, ASCE, 2005) Maintenance costs almost as high: if power lines last 50 years then $300 B / 50 years à $6B/yr just for maintenance Higher renewables generally means new transmission requirements

~ 7 % of electrical power lost in transmission

Losses due to: •  Joule hea=ng (I2R) (resis=ve losses) •  Inductance and capacitance (reac=ve power, AC only) •  Coronal discharge losses Tradeoffs in losses sets maximum voltage: -‐  Minimize resis=ve losses with large conductors (small R) and high V -‐  But V can’t be too high or makes more coronal discharge

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