Transmission Grid Fundamentals

3.15

Transmission Grid Fundamentals

A Papalexopoulos, ECCO International, Inc., San Francisco, CA, USA Ó 2013 Elsevier Inc. All rights reserved.

3.15.1 3.15.2 3.15.2.1 3.15.2.2 3.15.3 3.15.3.1 3.15.3.2 3.15.3.2.1 3.15.3.2.2 3.15.3.2.3 3.15.4 3.15.4.1 3.15.4.2 3.15.4.3 3.15.5 References Appendix A A.1 A.2 A.3 A.4 A.5 Appendix B B.1 B.2 B.3 B.4 Appendix C C.1 C.2 C.3

3.15.1

217 218 219 219 220 220 221 221 222 222 223 223 224 224 224 226 226 226 226 226 227 227 227 227 228 228 229 229 229 229 230

Transmission Grid Overview Transmission Grid Modeling NR Algorithm Fast Decoupled Power Flow Algorithm The Longer-Term Transmission Grid Problem Problem Overview Current Major Transmission Grid Challenges Transmission Planning Transmission Permitting Transmission Financing and Cost Allocation Incentives for Transmission Investments Introduction FTRs and Incentives for Expansion of the Transmission Grid Final Thoughts on Merchant Transmission Grid Expansions A Vision for Transmission Fundamentals: Concepts of Electric Power Systems Energy Voltage Current Impedance Power Electric Power System Structure Generation Transmission Distribution Load Fundamentals of Transmission Networks Overview Conductors Conductor Types and Size

Transmission Grid Overview

In this chapter, we present a brief overview of the transmission grid in the context of competitive energy markets. The transmission grid plays an essential role by providing the critical interconnection between suppliers and customers. It has been widely recognized that open access via the transmission grid is the key to a competitive electricity industry. However, the basic characteristics and limitations of the network must be properly addressed to achieve open transmission access. If transmission capacity for suppliers to reach customers is sufficient then the energy markets are simple and the market clearing straightforward. However, in most cases, transmission is a scarce resource and the transmission capacity limited. Hence, under normal conditions we need to deal with transmission congestion. The solution to the transmission congestion problem is fundamental to the way energy markets are designed and structured. Congestion occurs when there is insufficient transmission capacity to simultaneously implement all energy transactions that market participants submit to a regional transmission organization (RTO) in the forward markets, or all actual energy

Climate Vulnerability, Volume 3

flows that take place in real time. The major impact of transmission congestion is an overall increase in the cost of energy delivery. This cost is manifested by differences in the energy prices among injection and ejection locations in the network. The simple example of Figure 1 illustrates the impact of congestion in a system where a supply node A is connected to a demand node B through a transmission interface with maximum transfer capability qAB. Absent congestion, the

pB p pA

qAB A

B qAB

Figure 1

http://dx.doi.org/10.1016/B978-0-12-384703-4.00327-0

The impact of congestion.

217

218

Transmission Grid Fundamentals

market would clear at the intersection of the supply and demand curves at price p. Because of congestion, only qAB can be generated at A and consumed at B. This results in a lower price pA at A and a higher price pB at B. The price differential pB
pA is the cost of congestion and corresponds to the congestion revenue that would be the outcome of a marginal cost settlement for energy: The demand at B would be charged pB and the supplier at A would be paid pA, resulting in congestion revenue. The congestion revenue is usually paid to the transmission owner, either directly or indirectly through transmission rights. In the latter case, the congestion revenue is paid to the transmission rights holders who acquire the rights from the transmission owner through an auction administered by the system operator, (RTO in the United States or transmission system operator (TSO) in Europe). Financial transmission rights can be used as a hedge against congestion revenues (Treinen and Papalexopoulos 2002, 2005). In the example of Figure 1, if the supplier has a transmission right of qAB on the interface A–B, in the direction from A to B, the supplier would be unaffected by congestion because the additional congestion revenue at the price difference of pB
pA would elevate its effective price to that of the demand (pB). The simplest form of congestion management is deferring it to real time and clearing the forward energy markets as if there were no transmission constraints. This is equivalent to an unconstrained energy pool with a uniform forward energy price for the entire system. This is typical in many European market systems whereby the clearing by a power exchange produces a single price for an entire country. Congestion is addressed in real time by the TSO by an economic dispatch methodology that calculates optimal schedule adjustments to remove transmission constraint violations. To maintain a uniform price, these adjustments can be settled as bid and the net cost recovered by uplift. Clearly, the success of this approach would depend on the severity of congestion and the level of the uplift. If congestion is not small, forward energy market transactions could turn meaningless and large uplifts could distort price signals, creating perverse incentives in the marketplace. Even more significant is the so-called ‘dec’ game in which suppliers that cause congestion could end up being paid not to generate. This game was prevalent during the energy crisis in California in 2000 and 2001 (Joskow and Kahn 2001). In a system where congestion cannot be ignored, some level of congestion management is necessary in the forward markets. The focus is to capture the effects of commercially significant and predictable congestion. This approach is compatible with the flow-gate model wherein congestion is observed only on flow-gates in the forward markets. Similarly, a zonal variation would observe congestion only on interzonal interfaces. Any remaining congestion would be insignificant or unpredictable (in which case hedging instruments are useless) and it would not be possible to effectively address it ahead of real time because of insufficient information. This congestion is effectively addressed in real time. It can be priced on the margin, using Locational Marginal Price (LMP) settlement, or settled as bid recovering the net cost by uplift. In this case, however, the uplift ought to be small because significant congestion is already mitigated in the forward markets. If a detailed transmission network representation is required, congestion is observed in every path of the network. In this case

even when one transmission constraint becomes binding, every location in the grid will clear at a different price, resulting in LMPs at every node in the transmission grid.

3.15.2

Transmission Grid Modeling

System operators deploy various methodologies and modeling techniques to study the steady-state operation of the transmission grid under postulated conditions. Various forms of optimal power flow (OPF) techniques and optimization technologies provide this capability. In particular, in the context of energy markets, the purpose of the OPF is to determine the impact of a generation and load pattern on the flows on the transmission grid. These flows can then be checked against operational limits to determine if there are any violations. Power flow (PF) analysis is also deployed to examine the impact of contingencies. This processing is referred to as security analysis. The steady-state solution of the transmission network requires the solution of a set of nonlinear equations describing the balance of power at each location (bus). This is referred to as the dispatcher power flow (DPF) problem. The AC power flow equations, which describe the power balance at a bus, are a set of N complex equations, one for each bus, of the form
PNETk þ jQNETk þ Vk e
jqk

N X

ðGkm þ jBkm ÞVm ejqm ¼ 0

m¼1

[1]

k ¼ 1; .; N where N ¼ the number of electrical buses Vm ¼ the voltage magnitude at bus m Vk ¼ the voltage magnitude at bus k qm ¼ the voltage angle at bus m qk ¼ the voltage angle at bus k Gkm þ jBkm ¼ the (k, m)th element of the bus admittance matrix PNETk ¼ the net real and reactive power injections at bus k. QNETk The preceding set of complex equations can be separated into their real and imaginary parts forming two sets of (noncomplex) equations, which can be solved for an unknown set of V and q. P Pkm ðV; qÞ
PNETk ¼ 0 k ¼ 1; .; N m

P m

Qkm ðV; qÞ
QNETk ¼ 0

[2]

where Pkm ðV; qÞ ¼ the million watt (MW) flow on a branch connected between bus k and bus m Qkm ðV; qÞ ¼ the MVAR (unit that measures reactive power (1 MVAR = 1,000,000 VAR)) flow on a branch connected between bus k and bus m and the summation is performed over all branches connected to bus k. The MW flow on the branch k–m can be written as Pkm ðV; qÞ ¼ Gkk Vk2 þ Vk Vm ðGkm cosðqk
qm Þ þ Bkm sinðqk
qm ÞÞ

Transmission Grid Fundamentals and the MVAR flow on the same branch can be written as Qkm ðV; qÞ ¼


Bkk Vk2

4. Solve eqn [7] for 6X. 5. Update Xk (i.e., X kþ1 ¼ X k þ D; k)k þ 1) and return to Step 2.

þ Vk Vm ðGkm sinðqk
qm Þ


Bkm cosðqk
qm ÞÞ The set of equations given by eqn [2] form what is commonly referred to as the Static Load Flow Equations (SLFE). These equations, along with several power flow local control features, form what is referred to as the dispatcher’s power flow problem. The local control features are for maintaining a bus voltage at a specified value by varying a generator MVAR output, a transformer tap position, or a voltage control capacitor step position and for maintaining net interchange at a scheduled value. MVAR limits are respected on a generator during this process. Sometimes, it is convenient to have a more compact notation for the above equations. This notation is shown in eqn [3]. GðXÞ ¼ 0

[3]

where G is a set of nonlinear functions of a vector argument X. The vector argument X can be thought of as consisting of control variables, dependent variables, and fixed parameters. Some examples of the control variables are generator MW output, phase-shifter angles, and generator bus voltages. The dependent variables consist of bus voltage magnitudes and phase angles, as well as the MVAR output of generators performing bus voltage control. Fixed parameters are such items as the reference bus angle, noncontrolled generator MW and MVAR outputs, line parameters, etc. There are two different algorithms that are commonly used to solve the DPF problem. One is the Newton–Raphson (NR) algorithm and the other is the Fast Decoupled Power Flow (FDPF). Both algorithms will be briefly described in the following sections. The NR algorithm will be described first because the FDPF algorithm is derived from the NR algorithm.

3.15.2.1

NR Algorithm

The basic purpose of the NR algorithm is to solve the SLFEs. These are represented by GðXÞ ¼ 0

[4]

The solution to these equations is based on the vector matrix Taylor series expansion of G(X) about an initial state. The expansion is GðXÞ ¼ GðX 0 Þ þ JðX
X 0 Þ þ higher order terms

[5]

3.15.2.2

Fast Decoupled Power Flow Algorithm

The FDPF algorithm is another algorithm that may be used to solve the SLFEs (i.e., G(X) ¼ 0). It is derived by making some simplifying approximations to the Jacobian matrix of the NR algorithm that lead to a more computationally efficient algorithm. The first step in developing the FDPF algorithm is to reorder these equations so that all the real power balance equations are first, followed by the reactive power balance equations. This means that eqn [4] of that section may be rewritten as 3 2     Dq DP HM 7 ¼  4 DV 5 [8] DQ JL V where DP, DQ represent the mismatch in the real and reactive power (respectively) that arises from ignoring the higher order terms (i.e., they correspond to G(Xk)) Dq; DV=V correspond to DX H, M, J, L submatrices which make up the Jacobian matrix. These submatrices have the following definitions: vP ½H ¼ vq VvP z ½0 ½M ¼ vV vQ ½J ¼ z ½0 vq VvQ ½L ¼ vV

vGðXÞ evaluated at X ¼ X 0 vX

DP ¼ ½H  ½Dq  DQ ¼ ½L 

[6]

The solution process should drive G(X) to zero, so ignoring the higher order terms and letting DX ¼ X ¼ X 0 yields
JDX ¼ GðX 0 Þ

[7]

This equation   is solved iteratively for a series of new states, Xk, until GðX k Þ  3, a prespecified tolerance. The basic algorithm is as follows: k 1. Make an initial guess to the solution   X with k ¼ 0. k k   2. Evaluate G(X ). If maximum GðX Þ  3 then stop. 3. Build and factor J.

[9]

Elements of the off-diagonal submatrices, J and M, are much smaller in magnitude than elements of the diagonal submatrices, H and L, in the matrix equation, because of the weak coupling between the real power and the reactive power equations. Neglecting the off-diagonal coupling submatrices M and J, two sets of matrix equations are obtained:

where J is the Jacobian matrix: J ¼

219

DV V

[10]

 [11]

where Hkm ¼ Lkm ¼ Vk Vm ðGkm sin qkm
Bkm cos qkm Þ Hkk ¼
Bkk Vk2
Qk Lkk ¼
Bkk Vk2
Qk Further simplifications are made by observing that in most realistic situations [12] cos qkm y 1 Gkm sin qkm << Bkm

[13]

220

Transmission Grid Fundamentals

and Qk hhBkk Vk2

[14]

With these approximations, eqns [10] and [11] reduce to ½DP ¼ ½VB0 V  ½Dq

½DQ ¼ ½VB00 V 



DV V

[15]  [16]

where the elements of B0 and B00 are based on the branch susceptance terms. Taking the left-most V terms to the left-hand side of the equations and setting the right-most V terms to 1 p.u. in eqn [15], as V affects the MVAR flows mainly, eqns [15] and [16] reduce to 

DP V



¼ ½B0   ½Dq

  DQ ¼ ½B00   ½DV V

[17]

[18]

These equations are the FDPF equations. In calculating the elements of B0 and B00 , the following decoupling considerations are used: 1.1.1. Shunt elements and off-nominal transformers are neglected in B0 ; 1.1.2. Phase-shifter angle effects are neglected in B00 ; 1.1.3. Series resistances are neglected in B00 . The major advantage of these equations is that the matrices [B0 ] and [B00 ] only need to be calculated and factored once. This gives the FDPF algorithm a speed advantage over the NR algorithm. The basic algorithm for solving these decoupled equations is as follows: 1. 2. 3. 4. 5. 6. 7. 8. 9. 10.

Enter with factors of B0 and B00 . Set ITP and ITQ ¼ 0. Compute DP=V. If P is not converged, go to Step 5. If Q is converged, go to Step 9. Solve ½B0   Dq ¼ DP=V, update q and ITP. Compute DQ=V. If Q is converged, go to Step 9. Solve ½B00   DV ¼ DQ=V, update V and ITQ. If P and Q are converged, the solution is reached. If ITP or ITQ exceed the maximum number of iterations, exit unconverged. Otherwise, go to Step 2.

There are a few items that should be noted. First, the simplifying approximations that have been made are only in the linearization of the problem about the initial point. The calculation of the mismatches is performed in detail with no approximations. The algorithm continues to iterate until the solution of G(X) ¼ 0 is reached within a prespecified tolerance, usually 0.1 MW. Second, the modeling of control systems and other parameters, such as company interchange control voltage and transformer control, generator voltage-amperes reactive (VAR, unit that measures reactive power) limiting, distributed slack, matrix update, sensitivity calculations, contingency analysis, penalty factor calculation, power transfer distribution factor calculation, etc., are outside the scope of this chapter (Wood and Wollenberg 1984).

3.15.3

The Longer-Term Transmission Grid Problem

3.15.3.1

Problem Overview

There are few in the industry who would argue that the transmission system is currently well positioned to meet the growing demands of the restructured electric power industry. This applies not only to the physical infrastructure of the transmission networks, but also to the control and coordination of system operations. Restructuring of the industry has fundamentally altered the nature of the electric power business to facilitate large regional competitive wholesale markets. New risk-reward–focused business models introduced to the upstream and downstream power markets provide market incentives beyond the former cost-ofservice regulatory approach. At the same time, the continuing development of electric power spot markets has enabled a new breed of power marketers to trade power between low-cost and high-cost markets in response to both short- and long-term supply and demand fluctuations. Because electric power cannot be stored in a massive scale yet, but rather must be produced instantaneously as customers demand it, a robust transmission system is needed to allow these developing wholesale markets to function. These restructuring developments are increasing the reliance of industry – and the consumers that it serves – on the ability of the transmission system to operate dynamically in this new environment and its capability to handle short-term, market-driven power flow changes. However, recent trends in transmission investment and system operation experience indicate that the transmission sector is not keeping pace with the changing dynamics in the wholesale (and retail) markets (Federal Energy Regulatory Commission 2006). The problem is further magnified with the high penetration of renewable energy in the grid mainly driven by policy mandates. The problems facing the transmission sector are based on two fundamental issues: l

The transmission system was not designed to support market-driven electricity trading and massive penetration of renewable resources into the power system. l The transmission sector does not provide the incentives needed to support transmission investment and operations improvements necessitated by the changing industry structure and the policy mandates to support environmental goals. These policy mandates are prevalent in various forms in the United States and Europe today, as well as in other parts of the world. As a result of increased wholesale market trading activity and massive penetration of renewable resources into the power system, we are witnessing the following major changes in the transmission system: 1. The pattern of transmission usage is changing; there is a greater reliance on the capabilities of the transmission grid interconnections between various energy markets. 2. The transmission system is under stress, and transmission expansion has not kept pace with the changes in the interstate electricity marketplace. 3. Transmission investments are lagging (Kaplan 2009). As noted by the North American Electric Reliability Corporation (NERC), the use of advanced technologies such as superconducting materials, flexible AC transmission systems

Transmission Grid Fundamentals

(FACTS), or magnetic storage devices could improve transmission transfer capabilities over existing rights of way. However, the current framework does not provide significant incentives for rapid or large-scale transmission research and development initiatives. The ‘reasonable and prudent’ stipulation embodied in regulation often requires a lengthy approval process and cost– benefit analyses, increasing the costs of development and delaying the benefits. In addition, to the extent that the introduction of new technology yields significantly increased benefits to system users as compared to conventional technology with similar costs, the transmission owner will not reap greater rewards but will face greater risks, if it pursues new technology under traditional cost-of-service regulation. This will make transmission owners broadly indifferent or even averse to the use of new technology, because they are not rewarded for exceptional performance and innovation. Furthermore, even though transmission and generation investments are partial substitutes for each other in terms of meeting certain system requirements, generation is not always the most economically efficient means of solving a system problem. To the extent that the transmission system cannot deliver inexpensive electricity, more plants need to be built closer to load centers. Traditionally, in the vertically integrated utility structure, decisions affecting the trade-off between generation and transmission investment fell under a single locus of control, in which decisions were contingent primarily on state regulatory approval and oversight. Although state level regulatory control continues, business decisions concerning investment in these two types of resources under the new functionally unbundled industry structure are often in the hands of separate entities. As discussed, new merchant plants are often located at a distance from their target market, requiring transmission investments to be made even though the supply benefits will be realized elsewhere. The FERC noted this planning problem in Order No. 2000 (FERC Order 2000). In certain situations, transmission solutions may be more appropriate than increased generation development. Some of the system externalities that may be more appropriately facilitated through transmission investment are the following: l l l l l l

Expanded market competition through interconnection with multiple supply resources Reduced concentration in generation markets through interconnection with multiple supply resources Lower overall reserve requirements through access to capacity in neighboring regions Improved reactive power management Improved voltage stability Expanded flexibility in dealing with system emergencies and facilities outages

Although the economic decision between generation and transmission may be relatively clear, the lack of a balanced incentive structure between the generation and transmission sectors, coupled with the fragmentation of system planning among a larger group of market participants and the long schedules for building transmission compared to generation, has significantly tipped the investment balance toward generation. FERC’s Order No. 2000 attempted to rectify this situation. It provided for financial incentives to motivate transmission

221

owners to join RTOs. Among these incentives is the open invitation by the FERC to consider various forms of incentivebased regulation for the transmission sector. This invitation to consider regulatory approaches other than traditional cost-ofservice regulation is, in many ways, recognition of the increased risks and problems faced by the transmission sector and the inability of traditional regulation to effectively address these problems. The emergence of the renewable industry over the last 10 years has further complicated the transmission problem. In many jurisdictions, transmission constraints, especially across market boundaries, or across countries in Europe, have become a major impediment to further penetration of renewable energy into the power system. Although some boundary crossing lines have been built in the past, that experience underscores a number of obstacles such projects face. FERC’s Order No. 1000 (Federal Energy Regulatory Commission 2011) attempts to encourage the development of a market environment that is conducive to the resolution of this problem. Unfortunately, there is too little useful transmission planning at regional, interregional, or interconnection-wide levels; the costs of boundary-crossing projects can be allocated only through project specific negotiations; and the need to obtain construction permits from multiple authorities makes it difficult to site and build boundary crossing lines. Some have argued that the best solution to this suite of problems is to construct a nationwide overlay or ‘super-highway’ grid (U.S. Department of Energy 2008). Others favor large, discrete transmission projects that connect sizeable renewable resources to major load centers. Still others defend a more conventional buildup of transmission reinforcements – within regions and across multiple regional boundaries – and more use of local renewable resources. Depending on the specific conditions of each project any of these options could provide the optimal outcome. In the following subsection, we focus on specific major issues that are integral to the longer-term transmission problem.

3.15.3.2

Current Major Transmission Grid Challenges

In this section, we present the key challenges that continue to complicate investments in the transmission grid.

3.15.3.2.1

Transmission Planning

Traditionally, the transmission grid is expanded for reliability or economic reasons. The benefits of reliability are difficult to quantify and are often asserted to be spread over relatively wide areas. Only after reliability planning is complete do planners look for investments that would increase economic efficiency. Economic benefits include reduced network losses and mitigated or eliminated transmission constraints that prevent the use of the lowest-cost set of generators to meet demand. By strengthening the transmission grid, these projects also allow wholesale electricity markets to expand geographically, which mitigates market power and may provide other benefits. Of course, lines justified by economic benefits generally improve system reliability and vice versa (Joskow and Tirole 2005; MIT Study 2011). Recent years have seen very few transmission lines built that had been justified primarily on the basis of

222

Transmission Grid Fundamentals

economic benefits. However, the emergence of the renewable energy is forcing policymakers and RTOs to create a new category for policy-driven transmission investments to accommodate this type of energy. The planning process in most RTO regions is significantly more difficult than within vertically integrated utilities because decisions about the installation of new generation are the result of market forces (modified by state and federal support for renewables and other policies) rather than centralized planning. Thus, transmission planning in these regions is subject to additional uncertainties about where future generation may locate and how power will flow around the network, especially when renewable generators are involved. Magnifying this effect are uncertainties regarding future subsidies and requirements for renewable generation, because a painful fact of transmission planning is that it typically takes much longer to plan, get approvals, and build a high-voltage transmission line than a wind farm or solar generating facility. When generator build times are shorter than those for transmission, planners are forced to either anticipate new generation and build potentially unnecessary infrastructure or wait for firm generation plans before starting the process and thereby potentially discourage new generation investment. Given the large distances required to transfer renewable energy to load centers, consideration of interregional projects one at a time rather than as parts of an interconnection-wide plan is no longer sensible. It has become obvious that making more use of remote renewables in an efficient manner will require permanent planning processes at the interconnection level. According to FERC Order 2000, the key policy issues that need to be resolved with respect to transmission planning are as follows: 1. What should be the objectives of the planning process? For example, planning could be focused on renewable power development or on broader objectives, such as congestion relief and reliability enhancement. 2. What should be the scope of authority of the planning entities? Federal transmission planning could be run by interconnection-wide centralized authorities (the topdown approach) or be conducted primarily at a regional level (the bottom-up approach), or as a hybrid. 3. What is the appropriate scope of the planning process? Should the planning process extend beyond transmission planning narrowly defined to include a broader array of solutions to power system issues, such as demand response, distributed power, or conventional power plant construction. 4. Could preferential treatment tied to the planning process distort transmission investment? The planning proposals typically make available certain benefits, such as a federal permitting option, to projects included in the plan. These benefits could lead developers to add unnecessary features and costs to qualify proposals to meet plan criteria (e.g., proposing only high voltage lines if the plans have a minimum voltage threshold). Avoiding these distortions will require careful oversight or, arguably, limiting the benefits associated with the plan (e.g., putting all new power lines or none, whether or not they are in the plan, under federal government permitting authority).

3.15.3.2.2

Transmission Permitting

Interstate transmission projects require siting permits from every state the line will traverse. If any state disapproves a project, it will at best be delayed for rerouting or at worst canceled. As a result, projects are most vulnerable to challenge and litigation by parties who are not satisfied with the project for any reason. Challenges can take years to resolve. This permitting process has been a major obstacle to transmission investments. At the federal level, the Energy Policy Act of 2005 gave FERC authority to issue permits for facilities in areas experiencing capacity constraints or congestion and designated by the Secretary of Energy as a National Interest Electric Transmission Corridor (NIETC). These permits would confer rights of eminent domain if a state commission or other entity with authority to approve siting has withheld approval for more than 1 year after the filing of an application seeking approval. However, subsequent Circuit Court decisions made this authority effectively irrelevant, ruling that FERC cannot act if a state simply rejects rather than withholds approval of a project it opposes and that the process to designate NIETCs was flawed. In summary, the parochial interests of the states and localities do not naturally encompass the broader interests of larger regions or of the nation as a whole. Similar policy issues apply to cross border transmission investments in Europe. The simplest and most elegant solution to the problem of interstate transmission siting is to give FERC authority over significant interstate projects. Legislation should provide clear preemptive backstopping authority for FERC to site a transmission project after it has been approved by a regional planning entity, and a transmission project designated NIETC by Department of Energy (DOE). Legislation for electric transmission comparable to natural gas transmission should be desirable. It is, however, important to recognize that eliminating states’ roles entirely has a variety of disadvantages, given their superior knowledge of local conditions (Willrich 2009). Similarly for Europe, we believe that a top-down approach is recommended where an EU authority plans for transmission upgrades across EU member States.

3.15.3.2.3

Transmission Financing and Cost Allocation

The funding of transmission investments unfortunately exhibits some characteristics of the ‘chicken and egg’ problem, particularly as it applies to renewable energy. Renewable energy plant developers may have difficulty getting funding because the transmission to bring their power output to market is not in place, whereas the transmission projects cannot get loans because the generation that would justify construction of the new lines has not been built. This early funding issue is exacerbated by the typical development pattern for many renewable energy projects. The projects are built in phases over several years. However, it is not economic to build a transmission line in phases; the line must be built at once for the maximum anticipated capacity even if the full load will not be developed until years after the line is first put into operation. The most contentious transmission financing issue is cost allocation for new interstate transmission lines – that is, deciding which customers pay how much of the cost of building and operating a new transmission line that crosses

Transmission Grid Fundamentals

several states. Clearly, cost allocation is the single largest impediment to any transmission development. Since cost allocation issues affect transmission siting, these two issues must be linked and managed simultaneously. This is an important point, and most current transmission proposals fold the cost allocation issue into the transmission planning process. A simple way to resolve this problem is to allocate the costs of new projects that are part of an interconnection-wide plan to all customers in the interconnection (sometimes referred to as ‘socializing’ costs). The idea is that in a synchronized grid all ratepayers benefit to some extent from all transmission system enhancements. A related concept is that new transmission for renewable power yields environmental benefits to all ratepayers. A criticism of interconnection-wide cost allocation is that cost responsibility arguably becomes more diffuse and the incentives for cost discipline decline. Another criticism is that especially favorable funding for transmission could bias policymakers and investors away from other solutions to electric market problems, such as demand response or local renewable power. Other cost allocation approaches are being explored across the country but no approach is standard or even widely used (FERC Order 2000). In summary, state and federal regulatory agencies should continue to authorize for proposed transmission projects rates of return on capital sufficiently high to attract financing from their traditional sources. Under normal conditions, the capital required to expand and modernize America’s transmission grid may be attracted from the private sector. This assumes, however, a rational policy framework exists for planning, cost recovery and allocation, and siting of electric transmission facilities. Investor-owned utilities with strong balance sheets and independent transmission companies with requisite financial capacity should all play important roles in developing, financing, and owning the infrastructure.

3.15.4

l

l

l

Introduction

Just as restructuring of the electric power industry has increased and changed the risk profile of the predominantly deregulated wholesale and retail market participants, restructuring has also altered the risk profile of transmission owners. As regulated businesses, the increase in risk has not been as great for transmission owners as it has been for those upstream and downstream businesses more directly exposed to market forces. Nevertheless, risks do exist, including the following: l

l

Incentives for Transmission Investments

In this chapter, we present and analyze the risks transmission owners encounter in the restructured electric power industry and evaluate the potential for the emergency of merchant transmission grid expansions. In particular, we analyze the incentives financial transmission rights provide for the development of merchant transmission grid expansions.

3.15.4.1

l

Financial strength – Unbundled transmission entities are financially smaller than the former vertically integrated utility of which they were once a part.

l

223

Revenue diversity – Transmission entities are largely dependent on a single revenue stream coming from their transmission assets, in contrast to a larger diversified stream of revenue derived from the combined generation, transmission, and distribution activities of the former vertically integrated utility. This reliance on a single revenue stream, though regulated, still places greater risks on the transmission owner. Increased system demands – Transmission owners and operators need to spend considerably more time optimizing the operation and maintenance of their transmission assets to facilitate the rapid growth in wholesale trading. This increasing reliance on the efficient operation of the transmission system under demanding conditions increases the system performance risks faced by the transmission owners and operators. Increased market uncertainty – The lack of a defined endstate configuration for the transmission sector in the restructured environment increases the uncertainty for transmission owners contemplating investments. Uncertainty over such issues as changing usage patterns arising from the continuing evolution of the wholesale and retail electricity markets and the high penetration of renewable energy could make seemingly sound investments today less valuable than anticipated in the future. Under-utilization of investments in the transmission grid poses a real threat to transmission investors and new methodologies are needed to ensure that this problem is mitigated. Competitive threats – Stand-alone transmission entities will face increased competitive threats, such as those from merchant transmission development and distributed generation. Given the mismatch between committing to long-lived (e.g., 40–50 years) investments to satisfy customer requests without similar length customer contracts, transmission owners are exposed to significant risks. It is tempting to say that this does not matter, because a regulated entity can just roll-in any such ‘orphaned’ costs and recover them through higher rates for the remaining customers. However, such actions will require increasing prices and could harm a company’s competitive position. Counterparty risk – The growth of competition in the wholesale and retail electricity markets results in an expanding and changing variety of traders, marketers, aggregators, and other market participants requesting transmission service. This rapid increase in the number and diversity of transmission customers exposes transmission owners to increased counterparty financial risks that were not as prevalent for formerly vertically integrated utilities. Increased regulatory uncertainty – Significant uncertainty exists over the future regulatory rules for transmission. As we discussed earlier, it is imperative that a new framework of transmission investments is implemented where the key challenges of transmission planning, transmission permitting and siting, and financing and cost allocation are effectively addressed.

Whereas the risk profile for transmission owners and operators has increased, the reward structure has changed very little. Cost-of-service regulation still persists for almost every transmission owner in the United States. Although an increase

224

Transmission Grid Fundamentals

in the allowed rate of return on transmission investment is not the sole solution to the industry’s problems, it would signify the recognition of the increased risks faced by transmission owners. Increasing the allowed rate of return, either on new investment or the entire rate base, will improve the investment incentives for transmission owners, but it does not provide the necessary incentives for performance or customer service improvement. To address these issues, a new regulatory approach that provides incentives for both investment and performance improvement should be widely used. However, as part of the regulatory framework there is room for merchant transmission additions within regional transmission systems, that is, transmission additions executed by private market participants. To the extent that the actual market-based cost/benefit of an interconnection is not appropriately reflected through the existing regulatory model, the construction of that asset as a merchant facility may be a way to overcome this regulatory gap and satisfy customer demand. Benefits to system users increase with greater coordination of transmission maintenance, investment, and other decisions affecting system availability and operation. This is one of the principal tenets behind the FERC movement to group transmission owners into large-scale RTOs: The larger the area under a single locus of control, the easier it will be to facilitate markets and deliver benefits to customers. Several researchers have argued that, under a stringent set of assumptions, the merchant investment model has a remarkable set of attributes that appear to solve the natural monopoly problem and the associated need for regulating transmission companies traditionally associated with electric transmission networks (Joskow and Tirole 2005). However, in practice, the merchant transmission model has not received substantial traction.

3.15.4.2 FTRs and Incentives for Expansion of the Transmission Grid In principle, nobody should invest in grid expansions just to obtain rights to congestion rentals on the resulting additional capacity. Given the large economies of scale in grid investments, the principal effect of grid investments is to reduce or eliminate congestion rents. Additionally, the principal reason anybody would agree to pay part of the cost of a grid expansion is to create lower congestion charges for itself, which implies lower, not higher, congestion rents for the system. Thus, allocating Financial Transmission Rights (FTRs) to those who pay for a grid expansion will at best provide a minor increase in the incentive (or decrease in the disincentive) to join any coalition proposing to pay for a grid expansion. Resolution of the inherent conflict between FTR holders and future investments could possibly be achieved by proper coordination between transmission expansion and the FTR auction timeline. A new transmission facility for example should not be made available before the currently effective FTRs expire so that there will not be an impact on the FTR value. The reduced value of FTRs due to the transmission expansion will then be reflected in the next FTR auction and there will be no damage to FTR holders. Another related issue is the compensation to the investors that sponsor the transmission expansion. It is proposed that the investors will receive FTRs on the new transmission facilities.

However, once new facilities are in place, the value of these FTRs may be substantially reduced. Therefore, the motivation for market forces in transmission expansion may become questionable. Furthermore, transmission expansion will usually benefit many more market participants than the investors, even participants that enter into the market after completion of the project. How can the costs and benefits of transmission expansion be allocated equitably? A regulatory backstop is required to manage a large project and allocate its costs to all users, if market forces fail to sort out all problems. If the project also benefits consumers, it is important to make distribution companies pay part of the costs, which, in turn, would add these costs to the distribution charges paid by customers.

3.15.4.3 Final Thoughts on Merchant Transmission Grid Expansions The main issue related to merchant transmission grid expansions is the development of a regulatory system that fosters merchant transmission, who should pay for it, how much of it each will own, and how its cost will be recovered from future uses. Letting prospective alliances bid for a piece of the project based on their willingness to take risks on future usage is an idea worth trying – although adding FTRs to the process may not accomplish much, for the reasons outlined above. This process cannot provide a perfect solution to the problems of free riders and to the uncertainty about future usage. Nevertheless, there are no perfect solutions to these fundamental problems, and some version of this proposal may be feasible. Unfortunately, where grid investments are concerned, there may be no good alternative to maintaining a significant role for central planning and regulation. The objective of minimizing central planning and regulatory intervention in the market is understandable and commendable. Unfortunately, markets work badly when externalities are large and property rights are poorly defined, as they inherently are on an electricity grid. New, sophisticated theories and systems, such as identification of the most significant congested paths and frequent updating of these paths because of system configuration changes, can be used to create property rights and internalize externalities, so that the role of the market can be safely expanded and the role of regulated central planning can be reduced. However, it can be dangerous to roll back planning and regulation too far before putting good market processes in place.

3.15.5

A Vision for Transmission

The uncertainties, risks, and challenges with respect to transmission grid investments presented in Section 3.24.4 have resulted in under-investment in the transmission infrastructure in many parts of the world. Clearly, the evolution of the transmission grid is not keeping up with the rapid changes in the generation sector. An additional major challenge transmission operators and planners need to deal with in the future is related to the vulnerabilities of the transmission grid owing to climate variability. Climate vulnerabilities are mainly associated with the frequency and strength of weather extremes. The transmission grids are vulnerable to extreme events like flooding whereby

Transmission Grid Fundamentals

cable networks or pipelines can be broken due to land erosion. Also, high amounts of snow can result in the overloading of electrical transmission lines, which therefore can be broken. Similar results are associated with falling trees caused by snow, high winds, or land erosion by the water streams. Strong winds at specific locations (e.g., gorges) can create vibration in the lines that may result in serious problems. Transmission lines near the coastlines are vulnerable to sea salt deposition that reduces the resistance with a potential of leaking and sparking. Furthermore, transmission lines are exposed to serious damage from overloading in case of heat waves. Any perturbation in weather conditions, and especially extreme weather conditions, can increase/decrease the vulnerability of the transmission grid. Substantial investment in the transmission infrastructure and sophisticated communication technologies, along with sound regulatory policies, are required to ensure the development of a robust transmission grid that can effectively address the challenges of rapidly changing energy sector. Furthermore, the successful restructuring of the electric power industry in the United States and around the world depends, in large part, on the ability of the transmission sector to evolve and address the emerging problems facing the energy sector. These problems call for sound and bold implementation of innovative regulatory solutions and new business structures. The establishment of effective incentive regulation, coupled with unequivocal support for the development of forprofit transmission entities, offers the best solution to the mounting problems within the transmission sector. The additional revenues allowed to transmission entities for superior performance under such properly designed and implemented incentive plans would be more than repaid in cost savings and service benefits for electricity consumers. Consumers will benefit in several ways from a hybrid model of infrastructure development in which regulated and merchant transmission investments have an important role to play in securing a robust transmission sector. Even though the sector is not in crisis, major improvements in the regulatory and technological front are needed. Resolution of the key challenges such as transmission planning, permitting and siting, and cost allocation will greatly contribute to sound transmission investments that can lead to: 1. Lower prices 2. Improved service and reliability 3. Balancing economically efficient investment decisions between transmission and generation 4. Adoption of new technologies It is important to note that we should be concerned much more about under-investment in transmission than with overinvestment, because the societal costs of under-investment in transmission are much larger than the societal costs of overinvestment. External factors, such as licensing requirements, the need for rights of way, and ‘not in my back yard’ opposition to transmission infrastructure, already place significant constraints on overinvestment in major new transmission projects. The transmission grid of the future will look very different than that of the past. The transmission grid of the past was built for a specific business and technical model: Power plants would use transmission lines to move electricity to distribution

225

networks for delivery to customers. The power plants were large, central station facilities using fossil, nuclear, or hydroelectric energy sources, and were designed to run as-needed, when-needed. The power flow was one way, from the power plant to the customer. This model is already changing in major ways because of (1) variable renewable generation, (2) demand response, and (3) distributed generation. A key characteristic of these developments is potentially less predictability (in respect to availability and level of service) than traditional resources. The evolution of the current transmission model to an infrastructure with ‘smart grid’ capabilities is required to address these challenges. The smart grid involves the integrated operation of the power system from the home to the power plant. It will provide improved real-time transmission monitoring and reliability and consumer energy management (FERC Order 2000). The transmission monitoring includes real-time monitoring of grid functions, improved automated diagnosis and responses to grid failure, ‘plug and play’ ability, and enhanced ability to manage high penetration of renewable energy into the grid. The consumer energy management, via the Advanced Metering Infrastructure (AMI), includes a two-way communication between the customer and the utility, ability to respond to high prices through links between the smart meter and the consumer’s appliances, automated fault detection, easier management of distributed generation, and effective management of millions of connections of plug-in hybrid electric vehicles into the transmission grid. Finally, the smart grid is considered essential in managing the transition to a low-carbon economy and the successful implementation of sound environmental policies. It is important also to mention that much opportunity for innovation remains on the demand side beyond smart meters and device-level price signaling. Microgrid distribution architectures of the future will require a finer level of coordination between power consuming devices and the transmission grid. This coordination will become possible as high speed networks such as Internet broadband and 4G cellular communications become universal and will involve devices with WiFi connectivity. This is what is known in high-tech circles as “the Internet of Things.” These technologies will allow distributed generation resources across large populations of local wind and solar resources to be coordinated en masse, while ensuring local transmission and distribution constraints are met. The imprecise demand response programs of today will evolve to sophisticated network access control protocols analogous to those that govern communications devices that access wired networks and wireless spectrum such as Ethernet and Code Division Multiple Access (CDMA). Wide-scale distributed demand-side machine intelligence based on distributed computing-based stochastic control algorithms have recently been developed that provide fast and precise control over aggregate demand without significantly inconveniencing individual consumers (Ranade and Beal 2010). These innovations will result in a transmission grid architecture transformed from today’s central generation and distribution ‘fan’ model to one where demand information flows upstream from end consumers to the grid operators and utilities. This transmission grid architecture will allow for a more self-organized, flattened, microgrid-based network model similar to the Internet to evolve.

226

Transmission Grid Fundamentals

In summary, the following recommendations are considered essential for the adoption of coherent and stable national policies on greenhouse gas emissions, electric vehicles, demand response, and renewable and distributed generation. These recommendations would enhance investment incentives and thereby accelerate the appropriate evolution of the grid. 1. Continue to support organized wholesale electricity markets along with open, nondiscriminatory access to the transmission grid. 2. Implement new legislation to grant FERC enhanced siting authority for major transmission facilities that cross state boundaries. 3. Implement a sound framework for addressing transmission planning, permitting, and cost allocation issues. 4. Encourage the implementation of the smart grid and various technologies that allow two-way communications between the grid operators/utilities and the customer devices. 5. Implement new emerging demand response management technologies that will allow for the emergence of flexible demand to be curtailed when necessary in the mass market. 6. Encourage R&D for the development and implementation of new algorithms, methodologies, software, and communication systems into the transmission grid operations. 7. Implement better methods and tools for the collection and dissemination of transmission data.

Appendix A Fundamentals: Concepts of Electric Power Systems An electric power industry is composed of three basic components: generation, which converts primary energy resources into electricity; distribution, which distributes electricity to millions of consumers at home, work, and play; and transmission, which connects generators to distributors. Among modern, industrially advanced nations, America’s electric power industry is unique. It is largest in size, with about 1 000 000 MW of generating capacity, serving the largest economy in the world. To understand electric power systems, it is helpful to have a basic understanding of the fundamentals of electricity. These include the concepts of energy, voltage, current, direct current (DC), alternating current (AC), impedance, and power. The remainder of this section presents these basic concepts (Blume 2007).

A.1

Energy is the ability to perform work. Energy cannot be created or destroyed but can be converted from one form to another. For example, chemical energy in fossil fuels can be converted into electrical energy, and electrical energy in turn can be converted into useful work in the form of heat, light, and motion. Energy is measured in watt-hours (Wh) and for larger values is expressed in kilowatt (thousand watt, kW), megawatt (million watt, MW), gigawatt (billion watt, GW), or terawatt (trillion watt, TW) hours.

A.2

Blume, S., 2007: Electric Power System Basics. IEEE Press Series on Power Engineering, Wiley, John Wiley & Sons. Federal Energy Regulatory Commission, Order No. 697, July 20, 2006: Promoting transmission investment through pricing reform. Final Rule, 207–208. [Available online at http://www.ferc.gov/legal/maj-ord-reg.asp.] Federal Energy Regulatory Commission, July 21, 2011: Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, Order No. 1000. [Available online at http://www.ferc.gov/industries/electric/indus-act/transplan/fr-notice.pdf.] FERC Order 2000. [Available online at http://www.ferc.gov/legal/maj-ord-reg.asp.] Joskow, P., and E. Kahn, 2001: A Quantitative Analysis of Pricing Behavior in California’s Wholesale Electricity Market During Summer 2000. NBER Working Paper 8157. Joskow, P. L., and J. Tirole, 2005: Merchant transmission investment. J. Ind. Econ., 233–264. Kaplan, S. M., 2009: Electric Power Transmission: Background and Policy Issues. Congressional Research Service, Washington, DC. MIT Study, 2011: The Future of the Electric Grid. Ranade, V., and J. Beal, 2010: Distributed control for small customer energy demand management. IEEE SASO, Budapest, Hungary. Treinen, R., and A. D. Papalexopoulos, November 4–6, 2002: Transmission Rights Alternatives. Presented at the MED POWER 2002 Conference, Athens, Greece. Treinen, R., and A. D. Papalexopoulos, June 27–30, 2005: Important Practical Considerations in Designing an FTR Market. Presented at the IEEE PES Meeting, St. Petersburg, Russia. U.S. Department of Energy, 2008: 20% Wind Energy by 2030. U.S. Department of Energy, Washington, DC. [Available online at http://www.nrel.gov/docs/fy08osti/ 41869.pdf] and Southwest Power Pool, 2011: The Benefits of a Transmission Superhighway. Southwest Power Pool Communications Department, Little Rock, AR. [Available online at http://www.spp.org/.] Willrich, M., July 2009: Electricity Transmission Policy for America: Enabling a Smart Grid, End-to-End. MIT-IPC-Energy Innovation Working Paper 09–003. Wood, A. J., and B. F. Wollenberg, 1984: Power Generation, Operation and Control. John Wiley & Sons, New York.

Voltage

Voltage (also referred to as potential) is measured between two points and is a measure of the capacity of a device connected to those points to perform work per unit of charge that flows between those points. Voltage can be considered analogous to the pressure in a water pipe. Voltage is measured in volts (V), and for large values expressed in kilovolts (kV) or megavolts (MV).

A.3

Current

Current is a measure of the rate of flow of charge through a conductor. It is measured in amperes (A). Current can be considered analogous to the rate of flow of water through a pipe. Current can be unidirectional, referred to as ‘direct current,’ or it can periodically reverse directions with time, in which case it is called ‘alternating current.’ Voltage also can be unipolar – in which one point is always at a higher voltage than the other – or alternating in polarity with time. Unipolar voltage is referred to as ‘DC voltage’ as in Figure 2.

Voltage

References

Energy

Voltage is constant over time

Time Figure 2 Direct current (DC voltage). Steven Blume, “Electric Power System Basics,” IEEE Press Series on Power Engineering, Wiley 2007, a John Wiley & Sons, Inc. Publication.

Transmission Grid Fundamentals

Voltage that reverses polarity in a periodic fashion is referred to as “AC voltage” as in Figure 3. Positive voltage Peak positive

1 Period 0

Time

Peak negative Figure 3 Alternating current (AC voltage). Steven Blume, “Electric Power System Basics,” IEEE Press Series on Power Engineering, Wiley 2007, a John Wiley & Sons, Inc. Publication.

Alternating currents and voltages in power systems have nearly sinusoidal profiles. AC voltage and current waveforms are defined by three parameters: amplitude, frequency, and phase. The maximum value of the waveform is referred to as its ‘amplitude.’ Frequency is the rate at which current and voltage in the system oscillate, or reverse direction and return. Frequency is measured in cycles per second, also called ‘hertz’ (Hz). In the United States, as well as the rest of North America and parts of South America and Japan, the AC system frequency is 60 Hz, whereas in the rest of the world it is 50 Hz. DC can be considered a special case of AC, one with frequency equal to zero. The phase of an AC waveform is a measure of when the waveform crosses zero relative to some established time reference. Phase is expressed as a fraction of the AC cycle and measured in degrees (ranging from
180 to þ180 ). There is no concept of phase in a DC system.

A.4

Impedance

Impedance is a property of a conducting device – for example, a transmission line – that represents the impediment it poses to the flow of current through it. The rate at which energy flows through a transmission line is limited by the line’s impedance. Impedance has two components: resistance and reactance. Impedance, resistance, and reactance are all measured in ohms.

A.5

Power

Power is the rate at which energy is flowing or work is being done. Because voltage is the amount of work done for each unit of charge that flows and current is the rate of flow of charge, the product of voltage and current is the rate of work – power, or more precisely instantaneous power. Because power loss is equal to the resistance of a conductor times the square of the current, loss in a transmission line can be reduced by increasing the transmission voltage, which allows the current to be reduced for the same amount of power transmitted. As a result, long transmission lines employ high voltage. However, highvoltage lines also have drawbacks, including the need to maintain larger clearances to maintain safety. In AC systems, wherein voltage and current oscillate many times a second, the instantaneous power they produce is also

227

rapidly varying. Negative instantaneous power is equivalent to power flowing in the backward direction. In electric power systems, it is more valuable to have measures of power that are averages over many cycles. These measures are real power, reactive power, and apparent power. Only two of these three measures are independent; apparent power can be determined from real power and reactive power. Real power, also called ‘active power’ or ‘average power,’ is the average value of instantaneous power and is power that actually does work. It is measured in watts. Although instantaneous power can be flowing in both directions, real power only flows in one direction. Real power is zero if the phase difference between voltage and current is 90 . If the voltage and current waveforms are ‘in phase’ – that is, they cross zero at the same time – then instantaneous power, although varying, is always positive or flowing in one direction. In this case, all the power is real power. However, if one waveform is shifted in time relative to the other, a condition called ‘out of phase,’ then power takes on both positive and negative values, as shown. This phase difference can arise, for example, because of the reactance of the transmission line. Here, in addition to the real power that is flowing in one direction, there is back and forth movement of power called ‘reactive power.’ While it does no useful work, reactive power flow still causes power losses in the system because current is flowing through components, such as transformers and transmission lines, which have resistance. Reactive power is measured in volt-amperes reactive (VAR).

Appendix B Electric Power System Structure The electric power system consists of generating units where primary energy is converted into electric power, transmission and distribution networks that transport this power, and consumers’ equipment (also called ‘loads’) where power is used. Although originally generation, transport, and consumption of electric power were local to relatively small geographic regions, today these regional systems are connected together by high-voltage transmission lines to form highly interconnected and complex systems that span wide areas. This interconnection allows economies of scale, better utilization of the most economical generators, increased reliability, and an improved ratio of average load to peak load due to load diversity, thus increasing capacity utilization. Interconnection also leads to complexity, however, as any disturbance in one part of the system can adversely impact the entire system (Blume 2007). We discuss each of its subsystems next.

B.1

Generation

Electric power is produced by generating units, housed in power plants, which convert primary energy into electric energy. Primary energy comes from a number of sources, such as fossil fuel and nuclear, hydro, wind, and solar power. The process used to convert this energy into electric energy depends on the design of the generating unit, which is partly dictated by the source of primary energy. The term ‘thermal generation’ commonly refers to generating units that burn fuel to convert chemical energy into thermal energy, which is then used to

228

Transmission Grid Fundamentals

produce high-pressure steam. This steam then flows and drives the mechanical shaft of an AC electric generator that produces alternating voltage and current, or electric power, at its terminals. These generators have three terminals and produce three AC voltages, one at each terminal, which are 120 out of phase with respect to each other. From the operational perspective of the electric power system, generating units are classified into three categories: base-load, intermediate, and peaking units. Base-load units are used to meet the constant, or base, power needs of the system. They run continuously throughout the year except when they have to be shut down for repair and maintenance. Nuclear and coal plants are generally used as base-load units, as are run-ofthe-river hydroelectric plants. Intermediate units, also called cycling units, operate for extended periods of time but, unlike base-load units, not at one power continuously. They have the ability to vary their output more quickly than base-load units. Combined-cycle gas turbine plants and older thermal generating units generally are used as intermediate units. Peaking units operate only when the system power demand is close to its peak. They have to be able to start and stop quickly, but they run only for a small number of hours in a year. Large generating units generally are located outside densely populated areas, and the power they produce has to be transported to load centers. They produce three-phase AC voltage at the level of a few to a few tens of kV. To reduce power losses during onward transmission, this voltage is immediately converted to a few hundred kV using a transformer. All the generators on a single AC system are synchronized. In addition to the main large generating units, the system typically also has some distributed generation, including combined heat and power units. These and other small generating units, such as small hydroelectric plants, generally operate at lower voltages and are connected at the distribution system level. Small generating units, such as solar photovoltaic arrays, may be single phase.

B.2

Transmission

The transmission system is the most complex machine man ever built. It carries electric power over long distances from the generating units to the distribution system. The transmission network is composed of power lines and stations/substations. Transmission system power lines, with rare exceptions, are attached to high towers. However, in cities, where real estate is valuable, transmission lines are sometimes made up of insulated cables buried underground. Stations and substations house transformers, switchgear, measurement instrumentation, and communication equipment. Transformers are used to change the level of the transmission voltage. Switchgear includes circuit breakers and other types of switches used to disconnect parts of the transmission network for system protection or maintenance. Measurement instrumentation collects voltage, current, and power data for monitoring, control, and metering purposes. Communication equipment transmits these data to control centers and also allows switchgear to be controlled remotely. Because transmission networks carry power over long distances, the voltage at which they transmit power is high to reduce transmission losses, limit conductor cross-sectional area, and require narrower rights-ofway for a given power. However, to maintain safety,

high-transmission voltages require good insulation and large clearance from the ground, trees, and any structures. Transmission voltages vary from region to region and country to country. The transmission voltages commonly (but not exclusively) used in the United States are 138, 230, 345, 500, and 765 kV. A voltage of 1000 kV has been used on a transmission line in China. Although most transmission is three phase AC, for very-long-distance transmission, High Voltage Direct Current (HVDC) can be beneficial because transmission lines present no reactive impedance to DC. HVDC also only requires two conductors instead of three. However, HVDC transmission lines require expensive converter stations (utilizing power electronics technology) at either end of the line to connect to the rest of the AC system. Transformers at transmission substations convert transmission voltages down to lower levels to connect to the subtransmission network or directly to the distribution network. Subtransmission carries power over shorter distances than transmission and is typically used to connect the transmission network to multiple nearby relatively small distribution networks. In the United States, the commonly used sub-transmission voltages are 69 and 115 kV. The power that can be transmitted on a transmission line is limited by either thermal, voltage stability, or transient stability constraints, depending on which is the most binding. The thermal constraint arises because of the resistance of the transmission line that causes excessive power losses and hence heating of the line when the power flowing through it exceeds a certain level. The voltage stability constraint arises because of the reactance of a transmission line that causes the voltage at the far end of the line to drop below an allowable level (typically 95% of the nominal design voltage level) when the power flowing through the line exceeds a certain level. The transient stability constraint relates to the ability of the transmission line to deal with rapid changes in the power flowing through it without causing the generators to fall out of synchronism with each other. Generally, maximum power flow on short transmission lines is limited by thermal constraints, while power flow on longer transmission lines is limited by either voltage or transient stability constraints. These power flow constraints cause so-called congestion on transmission lines, when the excess capacity in the lowest-cost generating units cannot be supplied to loads due to the limited capacity of one or more transmission lines. Some very large consumers take electric power directly from the transmission or sub-transmission network. However, the majority of consumers get their power from the distribution network.

B.3

Distribution

Distribution networks carry power the last few miles from transmission or sub-transmission to consumers. Power is carried in distribution networks through wires either on poles or, in many urban areas, underground. Distribution networks are distinguished from transmission networks by their voltage level and topology. Lower voltages are used in distribution networks, as lower voltages require less clearance. Typically, lines up to 35 kV are considered part of the distribution network. The connection between distribution networks and transmission or subtransmission occurs at distribution substations. Distribution substations have transformers to step

Transmission Grid Fundamentals

voltage down to the primary distribution level (typically in the 4–35 kV range in the United States). Like transmission substations, distribution substations also have circuit breakers and monitoring equipment. However, distribution substations are generally less automated than transmission substations. Distribution networks usually have a radial topology, referred to as a “star network,” with only one power flow path between the distribution substation and a particular load. Distribution networks sometimes have a ring (or loop) topology, with two power flow paths between the distribution substation and the load.

B.4

Load

Electricity is consumed by a wide variety of loads, including lights, heaters, electronic equipment, household appliances, and motors that drive fans, pumps, and compressors. These loads can be classified based on their impedance, which can be resistive, reactive, or a combination of the two. In theory, loads can be purely reactive, and their reactance can be either inductive or capacitive. However, in practice the impedance of most loads is either purely resistive or a combination of resistive and inductive reactance. Heaters and incandescent lamps have purely resistive impedance, whereas motors have impedance that is resistive and inductive. Purely resistive loads only consume real power. Loads with inductive impedance also draw reactive power. Loads with capacitive impedance supply reactive power. Because of the abundance of motors connected to the network, the power system is dominated by inductive loads. Hence, generating units have to supply both real and reactive power. Because capacitors produce reactive power, they often are connected close to large inductive loads to cancel their reactive power (i.e., increase the effective power factor of the load) and reduce the burden on the network and the generators. From the power system’s operational perspective, the aggregate power demand of the loads in a region is more important than the power consumption of individual loads. This aggregate load is continuously varying.

Appendix C C.1

Fundamentals of Transmission Networks

Overview

High-voltage transmission lines transport power over long distances much more efficiently than lower-voltage distribution lines for two main reasons. First, high-voltage transmission lines take advantage of the power equation, that is, power is equal to the voltage times current. Therefore, increasing the voltage allows one to decrease the current for the same amount of power. Second, since transport losses are a function of the square of the current flowing in the conductors, increasing the voltage to lower the current drastically reduces transportation losses. Plus, reducing the current allows one to use smaller conductor sizes. Therefore, we increase the voltage to reduce the current and the losses (Blume 2007). A typical high-voltage transmission line is a three-phase 500 kV transmission line with two conductors per phase. The two-conductors-per-phase option is called bundling. Power companies bundle multiple conductors – double, triple, or more – to increase the power transport capability of a power

229

line. The type of insulation used in this line is referred to as V-string insulation. V-string insulation, compared with I-string insulation, provides stability in wind conditions. This line also has two static wires on the very top to shield itself from lightning. The static wires in this case do not have insulators; instead, they are directly connected to the metal towers so that lightning strikes are immediately grounded to earth. Hopefully, this shielding will keep the main power conductors from experiencing a direct lightning strike. Transmission lines can be built overhead or underground. Underground transmission is usually 3–10 times more costly than overhead transmission owing to right of way requirements, obstacles, and material costs. It is normally used in urban areas or near airports where overhead transmission is not an option. Also DC transmission systems are sometimes used for economic reasons, system synchronization benefits, and power flow control. In this case, the three-phase AC transmission line is converted into a two-pole (plus and minus) DC transmission line using bidirectional rectification converter stations at both ends of the DC line. The converter stations convert the AC power into DC power and vice versa. The reconstructed AC power must be filtered for improved power quality performance before being connected to the AC system. DC transmission lines do not have phases; instead, they have positive and negative poles. There are no synchronization issues with DC lines. The frequency of DC transmission is zero and, therefore, there are no concerns about variations in frequency between interconnected systems. A 60-Hz system can be connected to a 50-Hz system using a DC line. For economic reasons, a DC line may have advantages over the AC line, because the DC lines have only two conductors versus three conductors in AC lines. The overall cost to build and operate a DC line, including converter stations, may cost less than an equivalent AC line owing to the savings from one less conductor, narrower right of ways, and less expensive towers. The major types of equipment found in most transmission and distribution substations are presented next. Detail exhibition of the purpose, function, design characteristics, and key properties of each equipment is outside the scope of this chapter. The substation equipment includes (1) transformers, (2) regulators, (3) circuit breakers and reclosers, (4) air disconnect switches, (5) lightning arresters, (6) electrical buses, (7) capacitor banks, ( 8) reactors, (9) static var compensators, (10) control building, and (11) preventative maintenance equipment. We’ll close this section with a brief summary of conductors and conductor types and sizes.

C.2

Conductors

Conductor material (all wires), type, size, and current rating are key factors in determining the power handling capability of transmission lines, distribution lines, transformers, service wires, and so on. A conductor heats up when current flows through it owing to its resistance. The resistance per mile is constant for a conductor. The larger the diameter of the conductor, the less resistance there is to current flow. The amount of current that causes the temperature to rise depends on the conductor material and size. The conductor type determines its strength and application in electric power systems.

230

Transmission Grid Fundamentals

Utility companies use different conductor materials for different applications. Copper, aluminum, and steel are the primary types of conductor materials used in electrical power systems. Other types of conductors, such as silver and gold, are actually better conductors of electricity; however, cost prohibits wide use of these materials.

C.3

Conductor Types and Size

Power line conductors are either solid or stranded. Rigid conductors such as hollow aluminum tubes are used as

conductors in substations because of the added strength against sag in low-profile substations when the conductor is only supported at both ends. Rigid copper bus bars are commonly used in low-voltage switchgear because of their high current rating and relatively short lengths. The most common power line conductor types are (1) solid, (2) stranded, and (3) aluminum conductor, steel-reinforced (ACSR). With respect to the size, there are two conductor size standards used in electrical systems. One is for smaller conductor sizes (American Wire Gauge) and the other is for larger conductor sizes (circular mils).