NREL is a national laboratory of the U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, operated by the Alliance for Sustainable Energy, LLC.

Transmission Considerations for Market 

Operation: U.S. Design

Erik Ela 

Erik.Ela@nrel.gov

UWIG Workshop on Market 

Design and Operation With 

Variable Renewables 

22 June 2011

Fredericia, Denmark

NREL/PR-5500-52162

PIX 16562
The Largest and Most Complex (Man-Made) Machine 

in the World

• Transmission from X to Y can be 1,000s of miles.

• All generators and motors spin at about the same 

speed at the same time.

• A problem in Florida felt in Manitoba.

PIX 10926
A Market Like No Other

• So other than that what makes 

an energy market so unique?
A Market Like No Other

• Electrical energy cannot be stored:

• It can be converted to other forms of energy and stored but for very large 

costs and efficiency losses (e.g., pumped hydro plants).

• Energy is generated and consumed at almost the exact same 

time:

• Once the corn is harvested, it must be sold, transported, and eaten in a 

fraction of a second.

• Energy must be transported to consumers at the speed of light 

often from far distances.

• Laws of physics will dictate where power will go, who will get it, 

and how much of it will be lost along the way; NOT laws of 

economics:

• If the road is full of trucks, you can’t deliver anymore supply, and you can’t 

use a different road.

• There are many different ways to supply it, but the end product 

is the exact same thing no matter how it is supplied:

• Some suppliers have large capital costs and low variable costs, others are 

the opposite (price highly volatile even throughout day).
Outline

• Brief overview of U.S. Markets;

• The LMP: What is it, how is it calculated, and 

what does it do?

• How do variable renewable act in LMP 

markets?

• Financial Transmission Rights (FTR): What 

are they and how do they work?

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The Electric Utility

• Since electricity industry was first started, most 

electric utilities were vertically integrated:

• They owned and operated generation, transmission, and 

distribution.

• The utility reported costs to state utility commissions 

who then allowed prices to reflect those costs plus a 

reasonable rate of return on investment;

• Generally, trading electricity between utilities was 

rare and only usually occurred during emergency 

situations;

• In the 1960s and 1970s many power pools were 

formed to help coordinate electricity trading between 

utilities for both reliability and economic reasons.

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The Emergence of the RTO

• Electric Restructuring started in the mid-90s;

• FERC order 888 – Open access transmission;

• FERC Order 2000 – Encouragement of Regional 

Transmission Organizations (RTOs or ISOs);

• Different RTOs have varying responsibilities. These 

may include:

• Transmission planning;

• Overseeing bulk electricity grid operations;

• Maintaining generator/infrastructure interconnection queues 

and interconnection studies;

• Administering Wholesale energy markets and commitment 

and dispatch directions;

• Administering Ancillary service markets and ancillary service 

implementation;

• Other markets (e.g., financial transmission rights).

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North American Energy Markets

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How Do They Work?

• ISOs must be fair and unbiased;

• All sectors, all generator types, must 

be treated equally in the market;

• This becomes complicated since not all participants 

are equal in terms of technology and capabilities;

• Overall goal in energy markets is to create the least 

cost solution both short term and long term to 

electricity consumers while maintaining reliability 

levels;

• Spot prices influence the cost of energy;

• All market rules are decided on by agreement of 

market participants and FERC oversight.

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Congestion Management

• In the U.S., agreement that locational marginal prices 

(LMP) the most efficient way to manage congestion 

on the transmission system;

• LMP is the marginal cost of supplying load at 

individual locations;

• LMP calculated using optimal power flow:

• Sometimes with unit commitment constraints (day-ahead 

market);

• Sometimes with reserve constraints;

• Etc.

• Usually a dc power flow approximation:

• Voltage and reactive power usually ignored.

• Security constraints often considered.

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LMP

LMP = LMPenergy + LMPcongestion + LMPlosses

LMPenergy = λenergy: 

The marginal cost of providing energy on the entire 

system.

Will depend on the system reference bus.

LMPcongestion = Σαil

*μl: 

The marginal cost of congestion for that bus

αil : The generation shift factor, How much bus i

contributes to the congested line l.

μl

: Shadow price of congestion. How much that 

constraint impacts the total production costs.

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LMP

LMPlosses = (DF-1)* λenergy:

The marginal cost of introducing losses to the system.

DF: Delivery Factor. For every unit energy injection how 

much is delivered to loads.

Also depends on reference bus.

Note: Losses are usually approximated using linear 

techniques.

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LMP 2-Bus Example

1 2

Bus 1 Bus 2

Pload,1 = 0MW Pload,2 = 120MW

λ = 20, 

γ1 = γ 2 = γ 3 = γ 4 = 0,

μ+ = 10, μ- = 0

Flow = 100MW

LMP1 = λ-μ++μ- = 10 $/MWh LMP2 = λ = 20 $/MWh

Pgen,1=100MW Pgen,2=20MW
3-Bus Example

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2

3

1

G1Max: 100 MW

Price: 10$/MWh

G2Max: 100 MW

Price: 30$/MWh

What is the price at each bus:

• If the load is 50 MW?

• If the load is 150 MW?

• If there is a transmission constraint of 50 MW 

from bus 1 to bus 3?
3-Bus Example (LMPS)

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2

3

1

G1Max: 100 MW

Price: 10$/MWh

G2Max: 100 MW

Price: 30$/MWh

LMP1=10$/MWh

LMP3=30$/MWh

LMP2=20$/MWh

50 MW Limit

PG1=75 MW

PG2=75 MW
2

3

G1: 250 MW

10 $/MWh

Wind: Forecast 100 MW

G3: 100 MW

50 $/MWh

1

100 MW limit

L3: 250 MW

X12 = X13 = X23

LMP Impact of Renewables
Output, Cost, and LMP

Without Curtailment

Wind

Gen 

MW

Gen 1 

MW

Gen 1 

Cost

Gen 3 

MW

Gen 3 

Cost

Total 

Cost

LMP at 

Bus

Base 

Case 

(250 MW)

100 100 * $10/ 

MWh

+ 50 * $50/ 

MWh

= $3500

Add 1 

MW to 

Bus 1

100 101 * $10/ 

MWh

+ 50 * $50/ 

MWh

= $3510 $10

Add 1 

MW to 

Bus 3

100 100 * $10/ 

MWh

+ 51 * $50/ 

MWh

= $3550 $50

Add 1 

MW to 

Bus 2

100 102 * $10/ 

MWh

+ 49 * $50/ 

MWh

= $3470 $-30

$1500 or over 40% 

savings in total 

production costs.

Load pays $30 less.

Wind generator no 

longer is financially 

harmed to produce.

Other Benefits 

•Market-based solution that 

improves market efficiency 

while maintaining reliability

•Allows curtailment to 

proceed through scheduling 

software rather than manual 

intervention

•Less financial harm to wind 

and other generators.

Output, Cost, and LMP

With Curtailment

Wind

Gen 

MW

Gen 

1 

MW

Gen 1 

Cost

Gen 

3 

MW

Gen 3 

Cost

Total 

Cost

LMP 

at Bus

Base 

Case 

(250 

MW)

50 200 * $10/ 

MWh

+ 0 * $50/ 

MWh

= $2000

Add 1 

MW to 

Bus 1

50 201 * $10/ 

MWh

+ 0 * $50/ 

MWh

= $2010 $10

Add 1 

MW to 

Bus 3

49 202 * $10/ 

MWh

+ 0 * $50/ 

MWh

= $2020 $20

Add 1 

MW to 

Bus 2

51 200 * $10/ 

MWh

+ 0 * $50/ 

MWh

= $2000 $0

Allowing Wind to Participate in LMP Markets
Security Constraints

• In the U.S., security constraints will also impact 

the spot prices;

• The security-constrained unit commitment and 

economic dispatch programs run by the ISO will 

have selected n-1 transmission constraints;

• If line L1 fails, and the system would not be 

under limits following the outage without 

corrective action, the generator schedules will 

be re-dispatched;

• This will impact the LMP at all buses.

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Financial Transmission Rights

• Financial Transmission Rights (FTR) Markets –

When transmission congestion is apparent in the 

energy market, there may be more money collected 

from loads than is paid to generators.

• Market Participants bid on rights to these moneys by 

“financially” owning the transmission line where 

congestion occurs;

• Do not have to physically own line;

• Use to hedge against different prices between supply 

and demand.

19
Financial Transmission Rights

20

G1

Pmax = 200MW

$10/MWh

G2

Pmax = 200MW

$50/MWh

L2

Limit = 150MW Load = 300 MW
Financial Transmission Rights

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Gen 

Payments

Load 

Payments

G1 $1500

G2 $7500

L2 $15000

Total $9000 $15000

LMP = $50/MWh

Load = 300 MW

P2 = 150MW

P1 = 150MW

LMP = $10/MWh

???

Limit = 150MW
Financial Transmission Rights

• At the origin of the energy markets, it was found that 

physical transmission rights would not work for 

efficient and reliable operation of the system;

• Financial Transmission Rights are given through:

• Network integration service customers;

• Firm point-to-point service customers;

• FTR auctions;

• FTR bilateral transactions.

• FTR auctions run through optimization program 

reducing cost of all FTR bids:

• Power flow including security constraints.

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Incentivizing Transmission Investment

23

G1

Pmax = 200MW

$10/MWh

G2

Pmax = 200MW

$50/MWh

L2

Limit = 250MW Load = 300 MW

G1 invests in increasing capacity of line to 250 MW.

Now holds FTR of 100 MW.

G1 now makes the LMP of $50/MWh for his energy.
Incentivizing Transmission Investment

24

G1

Pmax = 200MW

$10/MWh

G2

Pmax = 200MW

$50/MWh

L2

Limit = 250MW Load = 300 MW

G1A sneaks in and undercuts G1, now LMP 

reduced back to $10/MWh.

G1 however still makes as much as $50/MWh for 

some of his energy due to his FTR.

G1A

Pmax = 200MW

$9/MWh
Impacts of Renewables on FTRs

• FTRs are generally not impacted significantly by the 

introduction of variable renewable resources;

• Renewable power producers should have ability to 

purchase FTRs if desired:

• Might reduce negative price impacts that occur.

• The variability of renewable might impact the change 

of power flow on system and therefore the prediction 

of the value of FTR;

• Significant difference in price between variable 

renewable bus location and load centers could 

incentivize merchant transmission investment 

through FTR process:

• Not sure this has occurred yet???

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Summary

• LMP and FTR seem to be working well in U.S. market 

regions;

• Renewables can have large impact on LMP and should be 

encouraged to participate in LMP markets;

• Renewables have not been seen on impact in FTR 

markets, however, can have impact on FTR through their 

impact on LMP pricing;

• Transmission is important!! When designing markets, 

incentives should not only be in place for locating 

generators and loads, but where to build transmission!

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References

www.isorto.org

Schweppe, F.C., Caraminis, M.C., Tabors, R.D. and Bohn, R.E. (1988) “Spot Pricing of 

Electricity”, Kluwer Academic Publishers.

Wood, A.J. and Wollenberg B.F. (1996) “Power Generation, Operation and Control”, Wiley 

Interscience.

Stoft, Steven. (2002) “Power System Economics: Designing Markets for Electricity”, Wiley 

Interscience.

Shahidehpour, M., Yamin, H., and Li, Z. (2002) “Market Operations in Electric Power Systems: 

forecasting, scheduling, and risk management” Wiley Interscience.

L. Chen et al, “Components of nodal prices for eelctric power systems,” IEEE Transactions on 

Power Systems, vol. 17, no. 1, Feb 2002.

J.C. Smith et al, “Impact of variable renewable energy on US electricity markets,” Proceedings of 

IEEE PES General Meeting, Minneapolis, MN, July 2010.

Lyons, Karen et al., “An Introduction to Financial Transmission Rights,” Electricity Journal, vol. 

13, no. 10, Dec 2000.

V. Sarkar et al, “A comprehensive Assessment of the Evolution of Financial Transmission 

Rights,” IEEE Transactions on Power Systems, vol. 23, no. 4, November 2008.

William Hogan, “Financial Transmission Right Formulations,” March 2002.

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Questions

Erik.Ela@nrel.gov

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