ABSTRACT

Transmission congestion occurs when there is insufficient transmission capacity to simultaneously accommodate all requests for transmission service within a region. In vertically integrated utilities it is not considered a big issue as the single entity has the ownership of generation, transmission and distribution and is able to manage congestion by instructing some plants to produce a bit more and some to produce a bit less until the system is balanced within transmission constraints, and none of generators has much reason to resist because theyall work for the same entity and all costs are pooled. But things are very different in a competitive system, where affected power plants will strongly resist requests to produce more or less than the amount that maximizes their profits given the market prices. Furthermore, electric power industry restructuring has moved generation investment and operations decisions into the competitive market but has left transmission, because of its inherent monopolistic nature, in the regulated environment. This mixing of competitive generation and regulated transmission makes congestion management more difficult in short term, medium term and long term because of coordination, planning and pricing issues. This report presents an overview of various challenges that deregulated electricity markets are facing and discusses different market based congestion management techniques employed in centralized and decentralized electricity markets to tackle these challenges with focus on North American electricity market.

INTRODUCTION

Congestion occurs when the transmission network is not sufficient to transfer electric power according to the market desire as line flows exceed reliability limits [1]. On the basis of this definition, congestion management can be defined as the actions taken to avoid or relieve congestion on the transmission network. We can divide these actions into three main categories:1. Wire Solutions

Building a new transmission line 2. Non-wire solutions

Use of FACT devices, transformer tap changing, phase shifters, curtailment or addition of generators at desired locations or curtailment of load downstream to give transmission load relief.

3. Economic or market solutions Locational marginal prices (LMP) Financial transmission rights (FTR) Flow gates rights (FGR)

Focus of this report will be on the third category, economic or marketsolutions in different North American markets. In general, congestion management can be considered as any systematic approach used in scheduling and matching generation and loads in order to manage congestion. The main challenge for congestion management in competitive market is how it can be implemented so that it efficiently supports competition in the bulk power market.

Effective congestion management is crucial, especially in the deregulated market, because of its economic impact on the efficient operation of electricity market. Congestion management has an importantimpact on spot prices, the degree of competition and the bidding incentives for energy market participants. In the short term, the objective of congestion management is to maintain the physical and operational reliability and security of the electricity transmission network and to facilitate a competitive electricity market. In the longterm, congestion management will impact on the investment decisions of new generators, loads, network transmission infrastructure at the existing and potential congested locations. It has been recognized thatcompletely eliminating all transmission congestion is neither necessarynor efficient. In other words, congestion management should compromise between the benefits and costs of solutions.[2]

Looking at the worldwide implementation of CM schemes, different approaches can be identified. A pool-based or centralized market designallows for the use of locational marginal pricing (LMP), zonal pricing concepts such as market splitting or flow-based market coupling try to increase market liquidity by still relying on centralized elements, whereas explicit auctioning of transmission capacity exhibits the

lowest degree of centralization, and thus, provides the greatest freedom to traders[3]. However, in Alberta, a section of the transmission regulation requires the Alberta Electric system operator AESO to construct a robust and unconstrained transmission system.

The rest of this report is structured as follows: First we will discussthe main causes of congestion management and the solutions from engineering perspective. Then we will briefly describe the congestion management from the perspective of vertically integrated and deregulated market structure. Then we will discuss the impact of congestion management on economics and reliability of electric power system. Finally, we will discuss in detail main challenges for congestion management in deregulated markets and various approaches that are being used in Alberta and PJM centralized deregulated electricity markets to meet these challenges.

I. CAUSES OF TRANSMISSION CONGESTION

There are various causes of transmission congestion. Three major and most common technical causes are:

1. Thermal limits2. Voltage drop regulation3. Voltage stability limit

Transmission capacity can be limited by the thermal limit which is the maximum amount of electrical energy that can be transmitted on the transmission line without overheating. Thermal limits are determined bythe weather and physical properties of the line and therefore it is notconstant throughout the year. The maximum power flow through the transmission line can also be limited by voltage drop regulation which is the range of acceptable voltage deviation. Voltage drop is a regulated value normally +/- 5% of the supply voltage. Voltage stability is the ability of a power system to maintain steady acceptable voltage at all the buses in the system under normal operating conditions and after being subject to disturbance.

Implications of the above three causes of congestion on transmission congestion and solution can be briefly explained by a simple two bus example shown in figure 1.

Figure 1Power flow equations are

Using bus 1 as a slack bus, the relationship between V2 and PL for the two bus system, with lower voltage regulation limit of 0.95 pu, 95% margin from the vertex of the curve for steady state voltage stability limit and thermal limit of 1200 MW (12 pu), are show in figures 2 and 3for a short (50 km) and long (150 km) respectively.

Figure 2

Voltage drop

Figure 3From figure 2 it is clear that for a short, 50 km, transmission line, the limiting factor in determining the power flow through the line is the thermal limit. The long term solution in this case would be to add a transmission line or a generator at bus 2. On the other hand, from figure 3 it is clear that for a long, 150 km, transmission line, the limiting factor in determining the maximum power flow through the line is voltage regulation limit. In this situation a feasible and logical solution would be to use FACT devices. II. CONGESTION MANAGEMENT : VERTICALLY INTEGRATED VS DEREGULATED

ELECTRICITY MARKETS

In traditional vertically integrated structure, all the control functions, like automatic generation control (AGC), economic load dispatch, unit commitment, ancillary services requirement decisions etc., are carried out by a single entity. Generation is dispatched in amanner that realizes the most economic overall solution. In such an environment, an optimal power flow can perform the dual function of minimizing generation costs and of avoiding congestion in a least-cost manner. Congestion management thus involves determining a generation pattern that does not violate the line flow limits. Line flow capacity

constraints, when incorporated in the scheduling program, lead to increased marginal costs. This may then be used as an economic signal for rescheduling generation or, in the case of recurring congestion, for installation of new generation/transmission facilities.

There is no doubt that competition in electricity markets has stimulated dramatic improvements in generation but the short-term coordination of the overall system is the main problem particularly when transmission congestion occurs. It is very difficult to design andimplement pricing systems that can replace monopoly central control of real-time operations. Various solutions have been attempted and the most effective solutions, however, are those that develop sophisticatedpricing systems in which the market rather than system operator makes more of the decisions. A competitive generation market needs a price-driven dispatch so that new competitors can get into the game with moreeconomical generation. But a price-driven dispatch does not necessarilyresult in the most efficient operations of a given mix of generating plants. Indeed, the primary problem in an electricity market is often to find ways to minimize the inefficiencies that can arise when a price-driven dispatch replaces a monopoly central dispatch.

III. CONGESTION MANAGEMENT: ECONOMICS AND RELIABILITY

Transmission congestion has major effect on the economics and reliability of electric power system. Although, it can be easily managed by curtailing generators and loads, arbitrarily restricting generators and loads can have significant economic costs. Economic and reliability implications of transmission congestion can be demonstratedby following simple example shown in figure 1.

Figure 1

Without any power flow constraint marginal cost at MCBUS1 would be equalto the marginal cost MCBUS2 of $ 20 MWh. If the line capacity is less than the load demand some power will have to be delivered by more expensive generator at Bus2 and MCBUS2 would be $40 MWh. Thus line congestion causes consumers connected to Bus2 to pay twice as much as without congestion. The impact of congestion on reliability is also evident from this example. With congestion in the line, the entire demand might not be met if the generator G2 on the load connected bus to was to fail.

In order to schedule transmission services reliably and economically, the system operator must understand the available transfer capability (ATC) as defined by physical capacities and the scheduled flows. If theATC is over-estimated, then real-time congestion could result in reducing system reliability below acceptable levels. On the other hand,if the ATC is under estimated, then economic exchanges are potentially sacrificed.

V. CONGESTION MANAGEMENT IN DEREGULATED MARKETS

There is no doubt that that deregulated electricity markets have brought many benefits to power system operations, however, they broughtwith them some issues and challenges for the market participants whether they are generation companies, transmission companies, independent system operators, retailers or consumers. Transmission congestion management is one of the most challenging one among all of them. Benefits Issues

Rapid Increase in generation capacity

Network Congestion Management

Efficient Capacity expansion Planning

Short term coordination of

overall system

Cheaper electricity due to competition and innovation

Transmission tariff

Logical and rationaldecision making

Ancillary Services Management

More choices to customers

Risk Analysis

Some of the main challenges that deregulated markets are facing in connection with congestion management are: To minimize the interference of the transmission network in the

market for electric energy To ensure secure and reliable operation of the power system To improve market efficiency Decision to manage power flow with existing transmission network or

to add new transmission line Decision between wire and non-wire solutions for managing congestion How congestion management solutions can be implemented so that it

efficiently supports competition in the bulk power market.In the rest of this report we will review and compare that how the different electricity markets in North America deal with these challenges.

VI. CONGESTION MANAGEMENT IN PJM, ERCOT AND ALBERTA MARKETS The electricity market statistics and boundaries of their grids are shown below:

Table 1

Electricity Market Alberta PJM

     Member Companies 164 750Millions of people Served 3.8 58Generation Capacity MW 13,632 178,847Peak Load MW 10,236 158,016Transmission Line km 26,000 90,000Annual Energy GWh 73,600 750,000Generation Sources 167 1,210Territory Sq. km 660,000 420,505

Market StructureCentralized pool based

Centralized pool based

Control Zones1 and 2 Intertie 18

Market Volume $ Billion 7.2 35.9Average Market Price $/MWh 76.22   Alberta-AIES PJM

A. ALBERTA ELECTRICITY MARKET

1. Market Structure

Alberta electricity market is centralized, single price, wholesale, hourly electricity market known as the Power Pool. The Power Pool is operated by Alberta Electric System Operator (AESO) an Independent System Operator (ISO). Besides wholesale market, the electricity marketin Alberta consisting of a number of inter-related sub markets as shownin Figure 4.

Figure 4 - Source: MSA- Alberta wholesale electricity market

Alberta market is Energy only market and generators are not paid for capacity. Generator must offer all available capacity to the market andall energy from generation must flow through the power pool. Pool prices are, therefore, relatively on a higher side.

In order to operate the electric system in a safe manner, the AESO needs operating reserves including regulating reserves, spinning reserves and supplemental reserves. These are procured by the AESO in aseparate operating reserves market called Watt‐Ex which is housed at the Natural Gas Exchange (NGX), as well as through Over‐The‐Counter

(OTC) transactions. In late 2007 a new sub market called Dispatch Down Service (DDS). The primary purpose of this market is to have generatorsvoluntarily step out of the energy market for a period to help offset the price depressing effects of some other generators who are forced into the market due to transmission constraints (known as Transmission Must Run, or TMR). Many generators and consumers choose to make their purchases ahead of real time and thus avoid being exposed to prices at the Power Pool. The buying and selling of electrical energy ahead of the production and consumption is done in the Forward Market. All the above markets relate to wholesale energy. The Alberta Retail Market is that market which ultimately serves the needs of the smaller retail customers, including all residential consumers. There is no formal day-ahead market Alberta[a].

As Alberta is a single pool price electricity market, forward financialcontracts commonly known as “Contracts for Difference” are used by the generation companies and load serving companies to hedge price risk in the spot market. It is basically a risk sharing tool that enables contracted parties to manage at least some portion of their exposure tovariations spot price. This fact can be demonstrated by a simple example:

Forward Financial Contract

If spot price = $45 If spot price = $55

Strike price=$50, Quantity= 40MW

End-user Payment to AESO=$2,200 End-user Payment to AESO=$1800Payment received by GenCorp from AESO= $2,200 Payment received by GenCorp from AESO= $1,800 Payment from GenCorp to End-user=$200 : 40(55-50) Payment from End-user to GenCorp=$200:40(50-45)End user net cost =$2000 End user net cost =$2000 GenCorp net revenue =$2000 GenCorp net revenue =$2000They have effectively traded 40MW at $50/MWh They have effectively traded 40MW at $50/MWhEnd-user has earned the benefit in this case GenCorp has earned thebenefit in this case

2. Congestion management

According to Alberta Reliability Standards, the AESO is required to maintain a robust and unconstrained transmission system to provide equal access to all consumers and generators to the grid. To comply with this standard, the AESO is required to plan a transmission system that is sufficiently robust so that 100 percent of the time transmission of all anticipated in–merit electrical energy can occur when all transmission facilities are in service. On an annual basis, the transmission system must be adequate so that at least 95 percent ofthe time transmission of all anticipated in–merit electrical energy canoccur when operating under abnormal conditions (N-1 contingency) [c]

Transmission Must Run (TMR) Service

In Alberta, special Transmission Must Run contracts (TMR) service is used to manage congestion. The use of Transmission Must Run causes generating units to be running or ‘constrained on’ when otherwise they would not. It interrupts the normal merit order. AESO plans for the TMR requirements in congested area and entered into contracts with generators to provide the service. Occasionally, other areas can become congested for brief periods

and a similar process is used to ensure units are running to maintain reliability and to meet the load.

Dispatch Down Service (DDS)

The fact that out‐of‐merit units are running to meet load (due to transmission constraints) puts downward pressure on Pool prices and the Dispatch Down Service was introduced to eliminate pool price distortion with the intention of improving the pool price signal. Dispatch Down Service is basically a price adjusting mechanism, in which in‐merit generators compete to be paid out to step out of energy market to help correct pool price for the effect of TMR. Eligibility for dispatching DDS is also determined by the system marginal price. If the system marginal price is greater than the TMR reference price, then no DDS is dispatched. Annual DDS service payments used to offset TMR dispatches from 2008 -2011 are shown in the table:

Wire Solution

Alberta transmission regulation encourages ‘wire’ solutions in order to comply with the objective of congestion-free robust transmission system. Some of the problems associated with this objective are: i. Capacity installed to meet peak period demand would not be

fully utilized in off-peak periods as shown in Figure ii. Over building of transmission system and extra cost to

consumers for providing service.iii. Marginal cost of reducing congestion using non-wire solution

may be less than marginal cost of reducing congestion through investment in ‘Wire’ solution

B. PJM ELECTRICITY MARKET

1. Market Structure

PJM interconnection operates a centrally dispatched, competitive wholesale electricity market and control the operations of 18 control zones. PJM operates day-ahead energy market, real-time energy market, capacity market, day ahead reserve market, regulationmarket and long term, annual and monthly FTR markets. Capacity resources must bid in day-ahead market and must make energy available for emergencies like sudden outage of generator or a transmission line, to avoid congestion on other lines. Failure to provide capacity results in capacity deficiency payments for the rest of the interval.

2. Congestion Management

Transmission congestion causes locational differences in marginal prices at each node as more expensive, out-of-merit, generators are utilized to maintain system reliability as shown in following example of power transfer between west and east regions:

Transmission

Locational Marginal Price (LMP)

Locational Marginal Pricing is an attempt by PJM to changetransmission congestion from a purely technical problem toone solvable by economics. In PJM market, incentives for investment in power generation and new transmission lines are achieved very efficiently through Locational Marginal Pricing (LMP).

LMP is defined as the marginal cost of supplying an extra MW of load at specific location (node or bus). LMP at any bus is made up of three components: the system marginal price (SMP), the marginal loss component (MLMP) and the congestion component of LMP (CLMP). Total congestion costsequal net congestion cost plus explicit congestion costs plus net inadvertent congestion costs. Net congestion costis the difference between load congestion payments and generation congestion revenue. Explicit congestion costs are associated with point to point transactions and net inadvertent costs are the difference between the net

actual energy flow and the net scheduled energy flow into or out of the control area[d]

LMPs at various trading hubs are shown in Figure .LMPs attrading hubs are the average of LMPs at all the nodes within 100 km radius of that hub. Traders can settle the transactions based on LMPs at hubs whereas generators and consumers are paid and charged on the bases of LMPs on their particular nodes.

LMPs are generated at five-minute intervals and immediately posted on (Open Access Same-time Information System) OASIS. Figure shows LMPs in Minnesota and Easternhubs with five minute intervals:

Figures and give us some idea of the effectiveness of LMP in communicating that where the congestion is and how prices are changing and giving economic signals to generation companies and transmission network operators for future investments.

FINANCIAL TRANSMISSION RIGHTS

Contracts for difference work well when there is no transmission congestion in the system and system marginal price is the same throughout the system like in Alberta electricity market.However, this financial tool does not work when transmission system is congested. Some other financial tool is therefore required to consider the effect of LMP as a result of congestion in transmission system. PJM market uses FTRs to hedge against the risk of variation inLMPs.

“FTRs are financial instruments that entitle their holdersto receive revenue or require them to pay charges based on

locational congestion price differences. Their role is to provide a hedge against the uncertainty of high LMPs caused by congestion.”

The FTRs are initially auctioned and then traded

in secondary markets. The purchase of FTRs in effect guarantees the purchaser the LMP at the generation bus regardless of the LMP at the load bus. To get real advantage of this financial tool, however, user of FTRs must estimate the value of the rights they buy at auction.How the market participants are protected from difference in LMPs can be demonstrated by a simple example:

West and East regions have a contract for power transfer from West region to East region for 26MW at strike price of 50 $/MWh. West region also purchase 26MW of financial transmission rights from the PJM.

LMP at West bus = $40 and East bus =$50West region sells 26 MW at $45 and receives payment from PJM= $1170Eastern region purchase 26MW at $55 and make payment to PJM=$1430PJM collects 26 (55-45)= $260 in congestion surplusWest region collects 26(55-45)=$260 from PJMWest region pays East region 26(55-50)=$130West region net cost 26 x 50 = $1300

East region net cost 26 x 50 = $1300

CONCLUSION

VII. CONGESTION MANAGEMENT : ALBERTA ELECTRICITY MARKET

There are a few areas of congestion in Alberta that are managed by the AESO using special Transmission Must Run contracts (TMR).The normal economic order has to be adjusted that results in more expensive generation being dispatched ahead of less expensive alternative units

that are on the downstream side of the congested line. The use of Transmission Must Run causes generating units to be running when otherwise they would not. It interrupts the normal merit order. Occasionally, other areas can become congested for brief periods and a similar process is used to ensure units are running to maintain reliability and to meet the load. The fact that out‐of‐merit units are running to meet load (due to transmission constraints) puts pressure onPool prices and the Dispatch Down Service market was created as a mechanism to correct for this effect. In Dispatch Down Service market, in-merit generators compete to be paid to ‘step out’ of the market to help correct pool price for the effect of TMR [5].

Non-wire and wire solutions to manage congestion is still debatable in Alberta market as the Transmission Regulation allows the AESO to propose non-wires solutions to congestion in very limited circumstances[6].

References: [1] F. Hussin, M.Y. Hassan, K.L.Lo, “Transmission congestion managementassessment in deregulated Electricity Market” 4th Student Conference on Research and Development (SCOReD 2006), Shah Alam, Selangor, MALAYSIA, 27-28 June, 2006

[2] Xiao-Ping Zhang “Congestion management – Challenges and solutions” Power Industry International 2007

[3] T. Krause, “Congestion management in liberalized electricity markets - theoretical concepts and international implementation,” EEH – Power Systems Laboratory, Tech. Rep., 2005.

[4] Kampa, A.F.K.  Verstege, J.F. “Coordinated Congestion Management inTransmission Systems Operation Planning” Energy market, 2009, EEM 2009, 6th international conference on the European, Issue Date: 27-29 May 2009 On page(s): 1 – 6

[5] MSA “Alberta Wholesale Electricity Market” September 29, 2010

[6] Enmax “ Fostering the Efficient Development of Alberta’s Electricity Infrastructure through changes to the Transmission Regulation” May, 2008