Chapter 1

Introduction

The electricity power utilities in many countries have been, or are being,

restructured. This has been driven by the desire of Government to meet the increasing

demands for electricity by encouraging independent power producers. The consumers are

allowed to choose their electricity supplier on the basis of price and service provided. In a

deregulated system, operator’s goals are balancing consumer power demand using the

available generation and ensuring that economical and technical constraints are respected.

The prime economical aspect is the social benefit, i.e. power suppliers should obtain

maximum prices for their produced energy, while consumers should pay the lowest prices

for the purchased electric power. Prices have to be defined in a free market economy and

restricted only by power exchange rules. Charging methodology is one important scheme

in the deregulated environment in the way that it can be utilized to recover the investment

cost from network users according to their different impact on the network [3].

The long-run incremental cost (LRIC) pricing methodology developed by

University of Bath in conjunction with Western Power Distribution (WPD,UK) and

Ofgem (the office of gas and electricity markets, UK) has drawn lots of attention from

industry and academic circles and found its application in practice. Compared with the

existing long-run cost pricing methodologies, this charging model can produce forward-

looking charges that reflect both the extent of the network needed to serve the

generation/demand and the degree to which the network is utilized. The traditional LRIC

pricing is based on the premise that the demand in the system is continuously growing

over time, and there will always be a need for network reinforcement some time in future,

which has been modified to reflect how a nodal increment might change the loading level

of the distribution system with a negative load growth, and how this change can be

translated into the costs/benefits to the network [1, 2].

1

GENERATION

TRANSMISSION

DISTRIBUTION

Chapter 2

Power System Restructuring and Deregulation

Since power cannot be stored for marketing but must be sold the instant it is

produced, it was generally assumed that power sector had to be a vertically integrated

monopoly of generation, transmission and distribution [2].

Fig.2.1Vertically Integrated Structure

2.1 Forces behind the Restructuring of Power System

2.1.1 Unfair Tariff Rates-

Since transmission, distribution and generation were handled by a single utility,

the tariff was the average of all the costs of the different services including generation,

transmission and distribution and distributed among all consumers equally.

2.1.2 Lack of Public Resources for Future Development –

Since the power system was run by a single entity, mostly the central government

which work on the least cost method, this caused a financial failure in many developing

countries as they could not generate enough public resources for future expansion and

development of power system.

2.1.3 Political and Ideological Changes-

The reform structure depends or influenced by party politics in most cases.

2

GENERATION TRANSMISSION DISTRIBUTION

ELECTRICITY MARKET

2.1.4 Technological Advancement-

The advance in technology makes low cost power plants owned by independent

power producers very efficient. These independent power producers would not emerge

without reform.

2.1.5 Environmental Impact-

Without the reforms most of the generation was dependent on fossil fuels and

hence reform movement was required to decrease the dependence of electricity

generation on fossil fuels and introduction of renewable energy like solar, wind etc. and

thus decreasing the environmental impact of electricity generation.

2.2 Important Features of Deregulation

2.2.1 Vertically Integrated System Changed to Unbundled System-

Earlier the three components were bundled, if power system were operated and

monitored by a single utility but with the reregulation the components of power system

were unbundled.

Fig. 2.2 Different components of Reregulated Power System

The structural components representing various segment of electricity market are:

Generation Companies (Gencos) -

They are responsible for operating and maintaining generating plant in the

generation sector and in most cases owns the plant.

3

Distribution Companies (Discos) –

Discos assume the same responsibility on the distribution side as in a traditional

supply utility. However, a trend in deregulation is that Discos may now be restricted to

maintaining the distribution network and providing facilities for electricity delivery while

retailers are separated from Discos and provide electric energy sales to end consumers.

Another trend in developing countries is to sell to an investor, or to corporatize, portions

of the distribution system so that investment for reinforcement can be raised and better

operating practices implemented

Transmission Owners (TOs) –

A basic premise of open transmission access is that transmission operators treat

all users on a non-discriminatory basis in respect of access and use of services. This

requirement cannot be ensured if transmission owners have financial interests in energy

generation or supply. A requirement, therefore, is to designate an independent system

operator to operate the transmission system.

Power Exchange (PX) –

The PX handles the electric power pool, which provides a forum to match electric

energy supply and demand based on bid prices. The time horizon of the pool market may

range from half an hour to a week or longer. The most usual is the day-ahead market to

facilitate energy trading one day before each operating day.

Functions of PX-

receive bids from power producers and customers.

match the bids, decide the market clearing price and prepare scheduling time.

provide schedules to the ISO or transmission system operators.

adjust the scheduling plan when the transmission system is congested.

4

Independent System Operator (ISO) –

The ISO is the supreme entity in the control of the transmission system. The basic

requirement of an ISO is disassociation from all market participants and absence from

any financial interest in the generation and distribution business.

The ISO has three objectives-

security maintenance.

service quality assurance.

promotion of economic efficiency and equity

Scheduling Coordinators (SCs)-

SCs aggregate participants in the energy trade and are free to use protocols that

may differ from pool rules.

Fig. 2.3: Market Components and Functions

2.2.2 Regulated Cost Changed to Unregulated Price-

Since earlier the power system was a monopoly the tariff plans etc. were decided

and fixed single handedly in a regulated manner. With deregulation many companies

entered in the business of power system and tariffs etc. were decided by the market forces

in an unregulated manner.

5

Ancillary ServicesCompeting Generators

DispatchBid

Power Exchange Independent System Operator

ForecastSell ControlMonitor

Distributors Transmission Facilities

2.2.3 Consumer Changed to Customer-

With deregulation many companies entered in the business of power system and

hence the consumers which earlier had no choice changed to customer who can chose

from a verity of tariff plans, suppliers etc.

2.2.4 Monopoly Changed to Competition-

Earlier power system was a single utility and hence was a natural monopoly. With

deregulation many players came into the market and competition was introduced.

6

Chapter 3

Transmission Pricing

3.1 Introduction

Pricing of transmission services plays a crucial role in determining whether

providing transmission services is economically beneficial to both the wheeling utility

and the wheeling customers. Transmission pricing is one of the most complicated issues

in restructuring electricity supply because of the physical laws that govern power flow in

transmission network, and the need to balance supply and demand at all times. Since

generators and customers are all connected to the same network, actions by one

participant can have significant consequences on others making it difficult to investigate

the cost each participant is responsible for. Electricity unlike many other commodities

cannot be stored easily and supply has to match demand at all times. The transportation

of electricity is constrained by physical laws which need to be satisfied constantly in

order to maintain the reliability and security of the power system. It became obvious that

the transmission network is the main impediment to energy privatization. In all power

markets around the world, generation and distribution parts are horizontally unbundled

and have competition, but the transmission system is a natural monopoly and therefore it

should be regulated. In this situation, defining a pricing scheme for transmission services

to reduce the effects of transmission monopoly on market competition is very important.

In this respect, transmission pricing in an equitable transparent manner to provide

coherent economic incentives for efficient transmission operation and its expansion. To

compensate for the revenue requirements of the owners of the transmission system and

encourage its future expansion, transmission pricing schemes should be designed fairly.

Also the schemes must aim to achieve the objective of maintaining system security by

encouraging proper operation and maintenance of existing and investment in new

facilities [2].

7

3.2 Objectives of Transmission Pricing

Ideally, the transmission tariff policy and methodology should satisfy the

following objectives:

- Ensure revenues adequate to compensate for the costs of operation and

maintenance of the transmission system;

- Encourage the efficient use and development of the network, both in the short and

long term;

- Ensure equitable treatment of, and non-discrimination among, market participants

who use the transmission system;

- Establish a price structure which is economically sound, simple enough for users

to understand and transparent to administer;

- Provide pricing stability over time;

- Provide flexibility to adapt to changing circumstances in the short and long term;

- Accommodate embedded generators and private generation stations [2].

3.3 Transmission Pricing Paradigms

The goal of the pricing schemes is to allocate and/or assign a part of the existing

and the new cost of transmission system to wheeling customers. Transmission pricing

paradigms are the overall processes of translating transmission costs into overall

transmission charges. These paradigms are:

3.3.1 Rolled-in transmission pricing

In this paradigm all existing transmission system and the new costs of system

operation and expansion, regardless of their cause, are summed up (“rolled-in’) into a

single number. This cost is then allocated (divided) among various users of the

transmission system, including the utility native (retail) customers, according to their

”extent of use” of the transmission system. Some of these “allocation” methods are:

8

Postage Stamp Method-

It depends only on the amount of power moved and the duration of use,

irrespective of supply and delivery points, distance of transmission usage or the

distribution of loading imposed on different transmission circuits by a specific

transaction.

Contract Path/MW Mile Method-

In this method, a specific path between the points of delivery and receipt is

selected for a wheeling transaction called contract path. Loading of each transmission

line due to each transaction is obtained and multiplied by the line length and summed

over all lines in grid to find use of grid by the transaction. Transaction charged in

proportion to their utilization of grid. But in this power flow outside the contract path and

to neighboring utilities is not considered.

3.3.2. Incremental Transmission Pricing-

According to this paradigm only the new transmission costs caused by the new

transmission customers will be considered for evaluating transmission charges for these

customers. The existing system costs will remain the responsibility of utilities present

customers .Incremental cost of a transaction is evaluated by comparing the transmission

system cost with and without the entire transaction. It also considers the reinforcement

cost in it.

Short-run incremental cost pricing (SRIC)

Long-run incremental cost pricing (LRIC)

3.3.3. Marginal Cost Pricing-

It is the cost of loading a marginal increase in transacted power. In this approach

multiply the cost for a unit of additional transaction by the size of the transaction [2].

Short-run marginal cost pricing (SRMC)

Long-run marginal cost pricing (LRMC)

9

Chapter 4

Long Run Incremental Cost

Network charges are charges against network users for their use of a network in

order to recover the costs of capital, operation and maintenance of a network and provide

forward-looking, efficient messages to both consumers and generators. Network charges,

therefore, should be able to truly reflect the extent of the use of the network by network

users. Efficient charges can help to release constraints and congestion in the network,

deferring prospective network expansion or reinforcement. The present pricing

methodology adopted by the majority of the distribution network operators (DNOs), the

distribution reinforcement model (DRM), however, cannot provide location economic

signals as the costs of network assets are averaged at each voltage level. Long-run cost

charging methodologies, due to its merits of being able to reflect the cost of future

network reinforcement caused by the nodal increment are recognized as more

economically efficient. Most long-run cost pricing methods evaluate costs associated

with projected demand/generation pattern and subsequently allocate the costs among new

and existing customers. These approaches, however, can only passively react to a set of

projected patterns of future generation or demand, failing to proactively influence the

patterns of future generation or demand through economic incentives. Up to2005,

investment cost-related pricing (ICRP) utilized, which works based on distance or length

of circuits, is the most advanced long-run pricing model. One recent development in

long-run cost pricing methodology is the long-run incremental cost (LRIC) pricing

methodology developed by the University of Bath in conjunction with Western Power

Distribution (WPD, UK.) and Ofgem (the office of gas and electricity markets, UK.).This

charging approach examines how a nodal increment of generation/demand might impact

the time to reinforce system assets and then translate the time change into charges .The

decision concerning of being penalty or reward is based on whether the nodal

perturbation advances future investment or defers it. This method, compared with

existing long-run cost pricing approaches, can produce cost-effective charges that reflect

both the extent of the network needed to serve the generation or demand and the degree

10

to which the network is utilized. As being able to send forward-looking signals to

influence prospective network connections, this charging model has been adopted by

WPD in its EHV network and is being under consideration by several other DNOs [2, 4].

4.1 Long-Run Network Charging ModelIn the original LRIC pricing model, for components in network that are affected

by a nodal injection, there will be a cost or a credit associated for the injection according

to Whether the network investment is accelerated or deferred. In this charging model, the

time to reinforce is evaluated by assessing the time for a loading level to reach the full

capacity of system components under a certain load growth rate with and without the

nodal injection. The proper modeling and calculation of load growth rate, as a result, is

essential for this charging model.

The LRIC model is implemented using the following steps [2,4].

4.1.1. Present Value of Future Investment

If a circuit l has a maximum allowed power flow ofC l, supporting a power flow of

Pl, the number of years it takesPl, to grow toC l, under a given LGR (load growth rate) r,

can be determined with

C l=Dl∗(1+r )nl ( 4.1 )

Where, nl is the number of years taking to PlreachC l, taking the logarithm of it gives,

nl=logC l−log Dl

log (1+r )(4.2)

Assume that investment will occur in thenlth year when the circuit utilization reaches C l,

and with a chosen discount rate of d, the present value of future investment will be

PV l=Assetl

(1+d )nl(4.3)

Where, Assetl, is the modem equivalent asset cost.

11

4.1.2. Cost Associated With Power Increment

If power flow change along line C is ∆ Pl as a result of anodal injection, the time horizon

of future reinforcement will change from yearnl, to year nlnewdefined by

C l=( Dl+∆ Pl )∗(1+r )nlnew(4.4)

new investment horizon nlnew

nlnew=

log Cl−log(Dl+∆ P l)log (1+r )

(4.5)

The new present value of future reinforcement becomes,

PV l=Asset l

(1+d )nlnew

(4.6)

The change in present value as a result of the injection is given by

∆ PV l=PV lnew- PV l =Assetl ( 1

(1+d )nlnew

− 1(1+d)nl

) (4.7)

The incremental cost for circuit l is the annuitized change in present value of future

investment over its life span,

IC l=∆ PV l∗annuityfactor (4.8¿

4.1.3. Calculation of LRIC

The nodal LRIC charges for a node are the summation of incremental cost over all

circuits supporting it, given by

L RIC N= ∑l IC l

∆ Pinl (4.9)

Where,∆ Pinl is the size of power injection at node i, and here we assign it to be 1 MW.

12

Input system data

Base case power flow analysis

Base power flow

Incremental power flow analysis

LRIC charge evaluation

Use of system charges

4.1.4. Flowchart of LRIC The core of flow chart is contingency analysis, incremental power analysis and

charge assessment [4].

Fig 4.1 Flow Chart of LRIC Charging Model

4.2Parameters Influencing LRIC Charging

4.2.1 Load Growth RateDemand growth represents the increase in energy demand over time, occurring

through natural growth of a service territory resulting from the increased prosperity,

productivity or population. Load growth rate is an averaged index derived by annuitizing

the load growth in a particular time span. In the LRIC charging model, in order to

simplify the process of assessing time to reinforce without and with nodal injection,

assumed uniform loading growth rate along each circuit. In reality, however, loads at

13

different buses may grow at quite different rates, leading to relatively diversified loading

growth rate for each circuit.

4.2.2 Component Reinforcement CostGenerally, the reinforcement costs of circuits or transformers need to be recovered

though LRIC charging model. Based on their different functions or ownerships, these

branches can be roughly divided into two different categories:

Transformer/circuit branches which have certain reinforcement costs;

Transformer/circuit branches which have no costs (zero-cost branches).

Those zero-cost branches are mainly branches, whose costs have been recovered

from network users, or branches which are owned by network users, or branches which

are used to connect different part of the substations, such as circuit breaker, and switches.

All the components costs are annuitized through annuity factor into annuity costs, which

is the actual amount of reinforcement costs that are recovered each year [2].

4.2.3 Annuity FactorAn annuity factor is the present value of an income stream that generates fixed

income each period for a specified number of periods .The annuity factor can therefore be

multiplied by the periodic annuity payment to determine the present value of the

remaining annuity payments [2].

4.2.4 Discount rate

The interest rate used in discounted cash flow analysis to determine the present value of

future cash flows. The discount rate takes into account the time value of money (the idea

that money available now is worth more than the same amount of money available in the

future because it could be earning interest) and the risk or uncertainty of the anticipated

future cash flows (which might be less than expected).

14

Chapter 5

LRIC Pricing for Negative Load Growth Rate

5.1 Introduction

Long-run marginal or incremental cost pricing models account for capital

investment cost in the network as a result of generation/demand increment at a given

location. Traditionally, long-run incremental cost (LRIC) models assume that the demand

in the system is continuously growing (positive growth rates assumed); thus, the network

reinforcement is always required some time into the future. This positive growth rate

assumption however does not reflect the whole reality that distribution network operators

(DNOs) are facing. Some parts of the distribution network experience prolonged negative

load growth. This can be driven by heavy industries shifting to elsewhere in the country

or to other parts of the world [4,5].

Negative load growth rates could have two consequential impacts to the network

planning and operation:

when the network assets come to the end of their useful life, their replacement

can be smaller, and there would be cost savings to DNOs with smaller

replacements;

If the assets’ loading levels fall to zero before the end of their useful lives, then

the assets become redundant. There would be cost-saving in the maintenance and

operation of these assets and in the capitals if the assets are re-used elsewhere.

For an underlying negative load growth rate, the asset utilization in the network

can still vary significantly from one place to another. If the asset’s loading level is very

low, i.e., the asset has a huge spare capacity, and if this capacity is still increasing due to

a negative load growth, then there are great benefits to the network operator if the asset’s

loading level drops to zero. Through network charges, DNOs can encourage demand

customers to leave early or encourage distribution generation (DG) to connect at an

appropriate point in the network. If on the other hand, the assets’ loading level is very

high, then there would be little benefit to encourage demand to leave or DG to connect.

15

An extended LRIC model that calculates network charges for network assets with

prolonged negative load growth rates. The model aims to reflect:

The magnitudes of benefit to the network in the future when the asset’s utilization

drops to zero and

How a nodal perturbation might accelerate or delay the future benefits. For

network components that support a nodal power injection or withdrawal, there

will be an associated credit if the benefit is accelerated or a cost if it is delayed.

5.2 Mathematical Formulation of Long-Run Incremental Cost Pricing

For Negative Growth RatesThe time horizon to reach the network benefit is the time taken for the circuit’s

loading level to fall from the current level to zero, or for the unused capacity to grow

from the present level to the full capacity. The LRIC charge for the circuit is the

difference in the present value of future benefits with and without the nodal perturbation.

The proposed charging model can be implemented through the following steps.

Deriving the Time Horizon to Reach Network Benefit:

C l=Dl∗(1−r d)nl+Sl∗(1+rs)

nl (5.1)

Where circuitl has a maximum allowed power flow ofC l, supporting a power flow ofPl,

the number of years it takesPl, to grow toC l, under a given LGR (Load Growth Rate), rd,

Sl is the Spare capacity increasing with the rater s.

For a very small r s andrd, (1) can be expanded using Taylor’s series:

C l=Dl+Sl+(S l∗r s−Dl∗rd)nl (5.2)

For (5.2) to be true for all future yearsnl, the second term in the bracket at the RHS of the

equation must be zero; this leads to (3) giving the relationship between the growth rate of

the spare capacity and the load growth rate:

r s=(D¿¿l∗r D)/Sl ¿ (5.3)

Using r s from (5.3), the number of years for the circuit’s spare capacity to grow from Sl

to C l can be determined by

C l=(C l−Dl )∗¿¿ (5.4)

16

Rearranging the equation gives the time to reach the benefit as

nl=logC l−log (C l−Dl )

log (1+r s) (5.5)

Evaluating the Present Value of the Future Benefit: Assume that investment will

occur in thenlth year when the circuit utilization reaches C l , and with a chosen discount

rate of d, the present value of future investment will be

PV l=Assetl

(1+d )nl (5.6)

Where, Assetl, is the modem equivalent asset cost.

Evaluating the cost of an additional Power Injection or Withdrawal at node N.

If power flow change along line C is ∆ Pl as a result of a nodal injection∆ P¿ at node N,

the time horizon of future reinforcement will change from yearnl, to year nlnewdefined by

C l=(C l−Dl−∆ Pl)∗¿¿ (5.7)

Equation (5.8) gives the new investment horizon nlnew as

nlnew=

log Cl−log(C l−Dl−∆ Pl)log ¿¿

(5.8)

The new present value of future reinforcement becomes,

PV l=Asset l

(1+d )nlnew

(5.9)

The change in present value as a result of the injection is given by

∆ PV l=PV lnew- PV l =Assetl ( 1

(1+d )nlnew

− 1(1+d)nl

) (5.10)

Calculating the Long-Run Incremental Cost: The long-run incremental cost for

circuit l is the annuitized change in present value of future investment over its life span,

17

the nodal LRIC charges for a node are the summation of incremental cost over all circuits

supporting it, given by

LRICN=∑l ∆ PV l∗annuityfactor

∆ P¿

(5.11)

Where,∆ P¿ is the size of power injection at node i.

18

Chapter 6

Case Study and Results

The demonstration of the proposed approach is on a simple two-busbar network

as shown in fig. 6.1. The circuit Lf connecting busbars 1 and 2 is rated at 45 MW and

costs £31293400 at its modern equivalent asset value.

Assuming a discount rate of 6.9% and a load growth rate of ±1%, Fig. 6.2 gives

the LRIC charge versus circuit utilization for withdrawal power from busbar 2.

Bus 1 Lf Bus 2

D

Fig. 6.1 Two busbar network with demand D

×104

3.6

3.3

3.0

2.7

2.4

2.1

1.8

1.5

£/MW/year 1.2

0.9

0.6

0.3

0 20 40 60 80 100

% Utilization

Fig. 6.2 LRIC charges for Negative and positive Load Growth rates

19

1% Negative Growth Rate

1% Positive Growth Rate

For a negative growth rate, withdrawing power will increase the loading level of

the circuit, thus delaying the network benefit. The customer will be charged; this is

illustrated by the solid line in Fig.6.2.

When the circuit utilization is high, it takes a long time to reach the network

benefit; thus, the present value of future benefit would be very small. However, if the

circuit utilization is low, there would be imminent benefit to the network if the last few

customers would leave the network, thus having huge charges for additional power

withdrawal.

In contrast, a positive load growth rate will require network reinforcement in the

future; withdrawing power from node 2 will bring forward the time to reinforce the

circuit, thus giving rise to LRIC charges as shown by the dotted line. At high utilizations,

additional power withdrawal would trigger imminent reinforcement, hence having huge

network charges.

20

Chapter 7

ConclusionsLong-run incremental cost pricing methodology utilizes the headroom of network

components to translate the investment horizon with and without the nodal increment into

an incremental cost to the network .Unlike the existing long-run charging models, it does

not need to assume the size and siting of future generation or demand. Instead, it relies

entirely on the capability of the existing network to accommodate future generation and

demand, and thus provides a forward-looking economic price signal to proactively

influence the development of future generation/demand. This in turn helps the network

planners to form a more realistic projection in the future generation/demand patterns in

forward planning their networks. This charging model respects both the extent to which a

network is used as well as the level of utilization of the network components. The LRIC

charges monotonically increase as the degree of the circuit utilization increases reflecting

the acceleration of future reinforcement. The present LRIC charging principle is based on

the assumption that demand across the entire distribution network is continuously

growing over time and there would always be a need for network reinforcement some

time in future. In reality, there may be some parts of the network with prolonged negative

growth rate. The proposed pricing principle seeks to directly relate a nodal power

perturbation to its benefit to the network. This report illustrated that network charges

could vary drastically depending on the assumption of underlying load growth rates.

21

References

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Rates”, IEEE Transactions on Power Systems, 2011.

[2] Chenghong Gu, Furong Li, Lihong Gu , "Application of long-run network charging

to large scale systems",2010 7th International Conference on the European  pp.1–

5,2010.

[3] Loi Lai Lei Power System Restructuring and Deregulation, (Edited), John WileySons

Limited, 2001.

[4] D. Shirmoharnmadi, X.V. Filho, B. Gorenstin et al., "Some fundamental, technical

concepts about cost based transmission pricing , IEEE Transactions on Power

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