Aging T&D Infrastructures → Reliability Optimization

The primary negative effect created by aging T&D infrastructures is poor customer service reliability. All of the other impacts, which boil down to higher costs in one way or another, stem from the utility’s attempts to control the situation with regard to equipment breakdowns, safety, and dependability, or to improve reliability in the face of increasing equipment failure rates. Thus, “Planning for Aging Infrastructures” needs to consider operating costs and risk, and reliability and optimizing reliability gained per dollar, tailoring that reliability of service to consumer needs and utility targets.

Long Term Strategy and Value, But Not Long Term-Planning

It takes decades for an infrastructure to deteriorate to the point that aging effects seriously inhibit performance. The monies required for any viable solution are very large and must be spread over many years. Only programs that are basically continuous in nature can economically address the issues. Thus, a long-term view of the problem and its solutions is needed in order to develop a workable and affordable plan.

This means that at some place in the utility, long-term assessment and planning for aging equipment and infrastructures must take place. A utility must understand its present situation, where aging trends are taking its equipment fleet, and what it can expect from various strategies and approaches it can apply. Ideally, it will develop an overall strategy for when, where, how, and why it will address aging infrastructures and the issues they cause.

But this does not mean that all T&D planning need be done with a long-range perspective. Much of the planning at any utility is short-range – two to five years ahead, oriented, but despite that short-range plans and projects are made to fit within long-term strategy. Traditionally, such short-range planning was coordinated with long-term system and business strategy and needs via criteria and guideline formulae. For example, utilities make minimization of losses cost a long-term goal, specifically aimed at making the lifetime cost minimum. This is accomplished in planning which may look only two to five years ahead, by setting the coefficients of formulae used to compute lifetime losses costs as used in the final evaluation of options from a present worth standpoint.

Conceptually, the same criteria and formulae-based approach is used with respect to aging infrastructures (Figure 13.1).

• Corporate strategic long-range planning of and for aging is based on projection of current trends and corporate goals, eventually leading to an overall strategy and plan. This is generally a business-oriented plan but it provides budgets and metrics (for age, condition, etc.) that can be mapped to system and equipment needs. Examples will be given in subsequent chapters.

• Power delivery planners, working with the corporate planners, develop appropriate criteria, targets, and formula, that position cost and value computations and planning goals in short-range planning toward fitting the aging-related plan.

• These are then applied routinely in the short-range planning process. The result is that short-range plans developed in the two- to five-year ahead process will fall in line with both long-range needs and long-term strategy.

Figure 13.1 A utility’s long-range aging-infrastructure priorities are met by the short-range planning process by orienting it to a set of criteria, formulae, and guidelines determined from a long-range plan based upon the utility’s aging infrastructure strategy.

At times, the utility may need a special, initial planning effort leading to a program that initiates aging-related programs to get its effort “off the ground” so to speak – something that is basically making up for not having the three steps above for the past decades. This, too, will be discussed in subsequent chapters.

This chapter begins with a look at the basic purposes of planning and the five steps of the planning process (Section 13.2) reviewing the most common pitfalls in each. The purpose of short-range and long-range planning and how they interrelate to aging infrastructures is then discussed in Section 13.3. Section 13.4 then looks at the T&D planning process as implemented in most modern utilities, again emphasizing aspects that particularly interact with the aging infrastructure issues. Section 13.5 stresses the importance of the systems approach in all planning for aging T&D systems. Finally, Section 13.6 summarizes key points with respect to aging infrastructure system planning.

What is the Mission?

Planning is a decision-making process that seeks to identify the available options and determine which is the best for the situation at hand. Its purpose is to determine the best schedule of future resources and actions to achieve a company’s, an individual’s, or an organization’s goals with respect to power. Usually, among the major concerns of planning are financial considerations - minimize cost, maximize profit, or some similar goal. In addition, service quality and reliability are almost always considerations. And often, other criteria are important, including environmental impact, public image, and a host of factors that a utility, energy services company, or energy consumer must weigh in making a selection regarding power supply. But regardless, planning is the process of identifying alternatives and selecting the best from among them.

Before beginning the planning step, it is best for a utility to review its mission statement – its overall definition of what guiding purpose and value-system defines its goals. This is particularly true with respect to meeting the challenge of aging infrastructures. Dealing with aging infrastructures, and getting what is desired in the outcome, means having focus and being realistic about constraints, goals, and capabilities. The mission statement is a good place to start. Given the realities of the situation, the aging system, a limited budget, regulatory pressures, is the current mission statement realistic? Making sure that the company’s mission statement matches both what it wants to do, now that it has assessed its aging infrastructure problem, and making sure that those principles are realistic and feasible, are big steps toward success.

A company’s “Mission Statement” succinctly defines the overall corporate objectives, while its economic goals explain its financial priorities. Usually, mission and financial goals have been incorporated in the economic guidelines and design procedures that the planner applies in his work. Regardless, while mission statements are often taken lightly by some employees, a review of the company’s mission and financial goals provides the planner with strategic insight into its planning guidelines and economic evaluation formula. Table 13.1 lists the mission statements from four large metropolitan electric distribution utilities in the United States. Planning goals for T&D, for DSM, for IRP, will be different among these utilities, because they have different priorities for what their executive management wants to accomplish. How the aging infrastructure problem will be handled in each utility and the priorities the utility puts of various approaches and solutions should be different as a result.

Mission statements are qualitative assertions of the overall philosophies and goals that lead to the quantitative engineering and economic criteria used in distribution planning. By understanding what their company is trying to do, the T&D planners have a better understanding of how to achieve those goals.

Table 13.1 Mission Statements of Four Electric Utilities

Planning: A Six-Step Process

Planning is a process of determining the best course of action or schedule of commitments that can be made to achieve one’s goals. The modern power delivery planning process can be segmented into the six steps shown in Figure 13.2. Each one is an important part of the process for planning in any type of industry, but in particularly utility T&D planning.

Any of the six steps, poorly performed, can lead to poor decisions, a poor plan, and ultimately failure to attain those goals. Mistakes and lack of focus in any step will lead planners astray, although the types of mistakes that result will differ, depending which one of the five was the first misstep. Below, each of the five steps is described, along with a brief summary of the goals for this step and pitfalls to be avoided in each. A lengthier discussion, with examples, can be found in Willis (2004).

Figure 13.2 Planning involves the six steps shown. See text for details.

Step 1: Identify the Scope of the Problem

Before beginning their work, every group of planners should identify their goal – exactly what they are trying to do. It is recommended that the planning problem and scope be formally written, as “this project involves planning of short- and long-term electric supply for all 821 homes planned for the new West Oaks subdivision.” This written definition of the scope defines the extent of the problem to be solved. All subsequent parts of the planning process should focus on that, and not stray (as some planners are often wont to do) to solve other problems or work in other areas. Trying to resolve a wide range of other problems in the nearby area at the same time this goal is achieved is not part of this project.

Step 2: Identify the Goals

A common mistake made by many planners is to begin their activity without specifying the goals for the particular planning situation at hand, or identifying how these goals might have changed from prior planning situations. It may be one thing to identify the problem, but the goals must explain in detail how to identify what the planners need to accomplish.

Goal definitions are quite different than mission statements. A mission statement lays out an organization’s direction, principles, and values. A goal defines explicitly what is desired to be accomplished in some situation. The former is strategic, the latter tactical. Time devoted to framing the planning situation at hand and explicitly defining the goal for it will be time well spent.

Again, as was the case with scope statement, it is best to produce a formal, written definition. This might read something like: “The goal is to develop a plan, able to be implemented within two years, which identifies all required equipment, labor, permits, and other expenses for electric facilities. This will provide the lowest long-term cost when evaluated on a present worth basis, and provide West Oaks subdivision with expected SAIDI and SAIFI of 2.0 hours and 1.25 events respectively, with all system factors meeting company standards.”

Aging Infrastructure Situations Often Encounter Severe Environmental and “Urban Fit” Constraints

Very often, particularly when dealing with aging infrastructure problems in the interior of older metropolitan areas, there are additional goals unique to a particular plan or situation. For example, it might be important to accommodate the esthetic and land-use preferences of local community leaders, or to use equipment or rights-of-way and sites already in inventory. Or, most often, a key requirement is to not require any new sites, rights of way, or visible disruption of an already crowded urban landscape. Some goals are unique to each particular case, created by an unusual situation or set of circumstances. Table 13.2 lists a number of special goals that are not uncommon to encounter when planning for an aging T&D system.

Table 13.2 Examples of Special Planning Goals or Criteria Often Encountered When Dealing with Aging T&D Systems

Step 3: Identify the Alternatives

This third step is often the most critical part of planning. This is identifying what could be done - all the alternatives open to the planner. What options are available? What variations on these options would be possible? This function encompasses determining the range of possibilities for solving the problem.

This is where the majority of great “planning disasters” occurs - the mistakes that lead, weeks later, to statements like, “Why didn’t we think of that?” For, while apparently the least challenging part of planning, a good deal of skill, breadth of thinking, and time, are required to identify the range of possibilities. Time and resources are always limited, and the temptation is strong to assume that one can see all the options just by “a quick look at the problem.” But this is seldom the case. A brilliant solution to an unusual problem most often comes from recognizing that there are also unusual options available to solve it.

Step 4: Evaluating the Alternatives

All alternatives should be evaluated against a common and comprehensive evaluation standard, one that considers every aspect pertinent to any option, and one that addresses all the goals. For power delivery planning this means evaluating alternatives against criteria and attributes that represent the utility’s requirements, standards and constraints. For DSM programs this means matching customer needs with marketing standards and guidelines.

Very often, the actual planning process will combine the evaluation and selection functions in a process designed to reject alternatives quickly and with minimum effort. Regardless, all alternatives should be evaluated completely with respect to everything that bears on the problem at hand. Planning methods should be examined carefully to make certain that they, too, like the various alternatives being considered, are complete.

Alternatives must be evaluated against both criteria and attributes. Criteria are requirements and constraints the plan must meet, including: voltage, flicker, other service standards, contingency rules, loading limits, safety and protection standards, and so forth. Such criteria only have to be satisfied: if standards allow voltages down to .95 per unit, then a design alternative is acceptable if it has voltages of .95 per unit, but no lower. On the other hand, attributes are values for which the planners wish to achieve the best performance possible: an attribute is a quality that is to be minimized (or maximized) while still meeting all criteria. One attribute in nearly all electric supply planning is cost. And while voltage drop, protection coordination, and other requirements are quantities that the planners would like to see exceed standards by comfortable margins, they should be treated as the criteria they are: good enough is good enough.

Traditional power delivery planning is single attribute planning, in that only the one attribute (cost) is to be minimized. This third step, evaluation, rejects the alternatives that do not meet all criteria and passed all the others. Among those left, the minimum cost alternative can be selected (in Step 5). Cost is a multi-faceted attribute, all aspects of which must be included in the evaluation: equipment, site costs, taxes, operations and maintenance, and losses. Table 13.3 lists some of the more common criteria and cost factors that need to be assessed in electric supply evaluation at the distribution level.

³ A common argument against this approach is that evaluation of “do nothing” is not needed because the answer is so obvious that it does not need to be included. But if that is the case, it is simple to do, so why not include it and document its evaluation?

Table 13.3 Some Typical Criteria and Costs Evaluated in Electric System Planning

Step 5: Selecting the Best Alternative

In many planning procedures, this function is combined with the evaluation function, and it is difficult to identify where evaluation ends and selection begins. In fact, efficient computerized planning methods that help planning engineers minimize the time and effort required to complete the planning process tend to combine Steps 3 through 5 into one process. But regardless, if the most important point in the identification-evaluation/selection process is the definition of “best,” it must match the goals and value system being used. The evaluation/selection method being used must mirror the desires of the organization, and be capable of distinguishing between alternatives in a valid manner in these areas.

A surprising number of planning mistakes, or inefficiencies, occur in the final selection process, because the planners do not assess alternatives on the basis of what is truly important to their goals. A planning method’s selection function should be examined to determine that it:

• Uses the definition of “best” that matches the planning goals. The fact that alternatives were evaluated on the basis of a particular attribute in Step 4 does not mean that it is weighted properly in the selection phase. For example, a common failure in T&D planning is to assess the value of electric losses in a distribution plan, but then fail to acknowledge their value in selecting the best design.

• Can accurately distinguish between alternatives. What are the limits of accuracy of the planning process? If it is only accurate to within 3%, then selection of a “best” alternative on the basis of its being 1% better than another is questionable. Error range in the evaluation and selection among close cases must be small enough to assure that the determination of “which is best” is accurate.

Many computerized planning procedures produce only approximate evaluations. Planners often fail to consider these limitations and interpret minor differences in computed evaluations as significant, when they are not.

Step 6: Being a Proponent of the Plan

This step is in many ways the key to success in the 21st century utility industry. Plans have to be sold to executive management, to stakeholders including in some cases stockholders, and in all cases, community and regulatory leaders. The planner is often heavily involved in this process and sometimes asked to lead it.

There are several critical points to keep in mind about this step. First, this represents a major change in perspective for the planners. In Steps one through Five, objectivity was a key. Make certain all options are considered on an equivalent and balanced basis to evaluate and report fully and fairly.

Once management’s approval process has selected of an alternative, the planner’s job changes. The planner, whose job was to objectively present the alternatives and their evaluation to management, now becomes a proponent whose job is to help sell that plan to all stakeholders. This can be a challenge, because management may have picked an alternative other than what the planner believed was best. Despite this, the planner’s job is to fully support carrying this option forward as the plan, helping sell it to all other stakeholders, and guide it through the regulatory approval process, until it is handed off as a fully authorized project to be built.

This job is easiest if the preceding five steps were well structured within a fully documented and institutionalized framework, used a credible planning method at every step, and was transparently and traceably documented throughout. Defensibility is often the most important element of a good plan.

Short-Range Planning: Decisions and Commitments

The purpose of electric utility short-range planning is to make certain that the system can continue to serve customer load while meeting all standards and criteria. This stage of planning is driven by the lead time - by the fact that it takes time to get things done and that decisions must be made ahead of this lead time.

Short-range planning must identify the commitments and purchases that must to be made today in order to allow them to be implemented in time to maintain service-within-standards in the future. In the case of the substation example given earlier, it takes five years to make all preparations. Therefore, the utility must plan at least five years ahead, so it knows when to “trigger” the process of creating that substation. Using a shorter lead time means selecting “do nothing” by default.

Table 13.4 Typical Minimum Lead Times at Various Levels of the Electric Utility Power System

The product of the short-range process is a series of decisions - the selection of various alternatives over other ones - for the expansion of the electric service facilities in various areas of the system. It is implemented as a series of projects, often one project per area and major decision, but sometimes with several lumped together into a larger project. Usually, the product of the planning process is a set of detailed project descriptions, each specifying what facilities and equipment are to be bought, where they will be put, how they will be fit into the system, as well as what other commitments and plans need to be enacted. Short-range planning initiates a process which then fills in the design and procurement detail and produces the land acquisition requests, drawings, permit requests, materials lists and construction authorizations, hiring, re-organization, marketing, advertising, customer survey, and other efforts necessary to make it happen.

Long-range Planning: Focus on Reducing Cost

Long-range planning focuses on making certain that the equipment and facilities called for in the short-range plan provide lasting value and the lowest overall cost during their lifetime, unlike short-range planning, which seeks to identify problems and solve them before they occur. The reason to look beyond the lead time, and to plan for the long run, is to assure the decisions being made have the most lasting value.

Figure 13.3 The short-range planning process consists of an initial planning phase in which the capability of existing facilities is compared to short-term (lead time) needs. Where capacity falls short of need, projects are initiated to determine how best to correct the situation. The load forecast is primarily an input to the short-range planning process, i.e., it is used to compare to existing capacity to determine if and where projects need to be initiated.

problems and solve them before they occur. The reason to look beyond the lead time, and to plan for the long run, is to assure the decisions being made have the most lasting value.

How can a planner know if a new distribution line, DG unit, or other electrical addition is a good investment, with a low lifetime cost and a high utilization over that lifetime? That lifetime begins when the new line is completed and put in place, which happens at the end of the lead time. Thus, long-range evaluation begins at the lead time and assesses cost, value, and equipment contribution over a lengthy period thereafter. Its purpose is to determine if the short-term decisions will have long-term value. Given typical economic factors, and considering the uncertainties in predicting conditions over the very long term, a ten-year period is generally considered the minimum for such economic evaluations.⁴

Handling Uncertainty: Multi-Scenario Planning

An important point to bear in mind is that long-range elements in their plan do not have to be built, committed to, or even decided upon, for years to come. This means that the utility can change its mind, or beyond that, be of two or more minds at the same time. There can be more than one long-range plan.

Uncertainty in predicting major events is a major concern in long-range planning. Will a possible new factory (employment center) develop as rumored, causing a large and as yet un-forecasted increment of growth? Will the bond election approve the bonds for a port facility (which would boost growth and increase load growth)? Situations such as these confront nearly every planner. Those of most concern to distribution planners are those factors that could change the location(s) of growth.

Figure 13.5 Multi-scenario planning uses several long-range plans to evaluate the short-range commitments, assuring that the single short-range decision, fits the various long-range situations that might develop. This shows the scenario variations for the case involving two possible future events.

In the presence of uncertainty about the future, utility planners face a dilemma. They want to make no commitment of resources and facilities for load growth that may develop, but neither can they ignore the fact that there are lead times required to put facilities in place, and that the events could happen. Given the reality of lead times, planners must sometimes commit without certainty that the events they are planning for will, in fact, come to pass.

Ideally, plans can be developed to confront any, or at least the most likely, eventualities, as illustrated in Figure 13.5. Multiple long-range plans, all stemming from the same short-range decisions (decisions that must be made because of lead times) cover the various possible events. This type of planning, called multiple-scenario planning involves explicit enumeration of plans to cover the various likely outcomes of future events. It is the only completely valid way to handle uncertainty in T&D forecasting and requirements planning.

Figure 13.6 Four scenarios of load density maps for a large U.S. city. See text for details.

Spatial Load Forecast

The planning process is driven by a recognition that future customer demands for power, reliability, and services may differ from those at the present. The load forecast projects future customer demand and reliability requirements, which define the minimum capability targets that the future system must meet in order to satisfy the customer demands. Forecasting for T&D planning requires a spatial forecast, as was illustrated in Figure 13.6.

Strategic Planning

No long term goals can be dependably achieved without planning on when, where and how they will be achieved. Utility strategic planning incorporates three aspects that directly interact with and even dictate elements of the T&D plan:

- Budget. The utility’s business and corporate planning sets spending limits and constraints. These are passed on to the T&D planning process through the budget approval process and have been a part of traditional T&D planning for generations.

- Integrated Resource Plans. The utility’s plan with respect to the use of distributed renewable energy, energy efficiency, demand response, and market-driven incentive plans, along with Smart systems and energy storage heavily influences what is needed from the T&D system.

- Aging. Aging is a long term effect and one that will affect no only utility spending and performance, but also the characteristics of that spending and performance (how much is capital, how much is O&M; how SAIFI and SAIF vary from circuit to circuit and their volatility year to year).

T&D planning needs to not only acknowledge and comply with all three elements of the utilities strategy, but ideally be driven by the strategic plan. Conversely, the utility must include all three of these elements, with respect to its system, in its corporate strategy. Essentially it must develop a strategy in these three areas of delivery system concern, if it is to build a base for comprehensive and effective planning – and hence effective use of its investment.

In the context discussed here, corporate strategy is not a spatial planning process. Costs, profits, and risks are not spatial, because money is fungible: a dollar made in the downtown area is just as valuable as a dollar made in rural areas.⁵ As a result the corporate plan and strategy will be unspecific as to locations and interactions with aging areas of the system. Its preparation will need to address the fact that there are aging areas of the system, etc., but locational information is not needed and not used.

This lack of need for spatial detail eases the strategic planning process. As will be shown in examples later in Chapter 16’s example and in the Appendices, “big picture” planning has to deal with the fact that the utility has so many old units, etc. Detailed implementation of that strategy through the T&D plan, however, has to both deal with specific areas and equipments, and tie the way it deals with them back to those elements of the plan and those required for expansion and other purposes. Lack of coordination so tight it could be called integration of expansion planning and aging-equipment refurbishment and replacement programs, will lead to noticeable inefficiencies in the use of capital.

Transmission Planning

In modern (deregulated) utilities, “transmission” has two very distinct meanings applied to two very different parts of the power system:

Wholesale grid: The regional grid, which interconnects generating plants and key bulk switching stations around the region, and connects the regional power system to other regions, is composed of high-capacity transmission lines, typically of voltages between 230 to 765 kV. This is the portion of the system that creates the wholesale market in electric power, and assures open access to merchant generators and buyers alike. System security, rather than reliability, is really the key factor in assuring “dependability” here.

Sub-transmission: The term sub-transmission has been used for decades to designate those transmission voltage lines whose purpose is to deliver power to distribution substations. This is a mission quite distinction from that of the wholesale grid. Sub-transmission lines are generally of between 35 and138 kV, although some 230 kV lines exist primarily for this purpose.

The regional wholesale transmission grid is a key element in a healthy and economical regionally electric industry – it creates or enables the open access competitive market for electric power. The wholesale grid is usually planned and operated by an independent regional authority somewhat distinct, and often at arms-length from, the distribution utilities. Only part of the criteria and goals at this level relates to delivering power. Without doubt, one purpose of the wholesale grid is to deliver the required power to customers, but in addition, the transmission system is planned to provide:

⁵ In utilities with service areas that overlap multiple regulatory jurisdictions, such as those that serve customers in several states, strategic and corporate plans do have to take the variations in state regulation and policy into account. In this respect strategic planning can become spatial.

1. System Security and Stability – the ability of the system to maintain interconnected integrity subsequent to any reasonably likely failure or event, and to react to transient events in a smooth manner.

2. Generation access (deregulation) or generation dispatch (traditional) – provide sufficient electric tie strength between generation plants and the system to assure all plants can truly access the system – that transmission constraints do not limit choice of what generation can be run.

These two goals mean that a good deal of the transmission system is planned from the perspective of generation: permitting generation access the system, ensuring system security no matter what happens, and providing stability against major disturbances. These aspects of transmission planning are not directly concerned with meeting power delivery needs, but with assuring that the generation-grid level of the system provides a stable bulk transmission capability and open access opportunity for all.

Planning of the “generation-grid” combination, which includes most of the high voltage transmission, is an activity quite apart from what might be termed “sub-transmission” planning - the planning of power transfer capability to the distribution substations, which is the only type of planning relevant to power delivery planning.

In general, sub-transmission planning reacts only slightly with grid planning - the grid is planned and presented as a “given” to the sub-transmission planning process. This is particularly true because of the “Chinese wall” that often has to exist between the wholesale (open access) and retail (local Distribution Company) under deregulation.

Thus, the interaction of the planning processes at the transmission-grid/sub-transmission-junction, has the most limited “coordination” of any of the junctions between adjacent levels of the power system. Sub-transmission is part of the power distribution planning process. It is best done as part of the distribution planning process. The sub-transmission – substation – feeder system ought to be planned as one system.

Figure 13.9 shows the recommended relation of sub-transmission planning to the other stages of utility system planning. Key aspects of these relationships include:

• Transmission encompasses two planning functions: as mentioned above, the “generation-grid” planning which focuses on establishing a strong grid with security and dispatch freedom and meeting all power pool requirements, and the “sub- transmission” planning, which includes all planning activities related to moving power to substations so that it can be distributed to customers. Only “sub-transmission planning” is overtly a power delivery planning function.

• Forecast of future load for transmission planning comes through the distribution planning process. Fully half of the statistical variation in future loads due to “load growth” is a function of distribution planning (Willis and Powell, 1985). To the transmission-sub-transmission planning process, the “loads” to be served by the system being planned are the high-side loads of the distribution substations. How much load is collected to a particular substation depends on the distribution planning - whether load growth ends up at one substation, or another, or is split between them is determined by the distribution planning. This “high side substation load forecast” is best produced by starting with the spatial forecast, assessing the preferred patterns of distribution substation service areas in the distribution planning/substation planning stages, and then passing the target substation loads to the transmission planning process. If particular loads prove difficult to serve, transmission planning can provide feedback to distribution planning, asking if alternate possibilities can be considered.

• Coordination with substation planning. The transmission system must reach every substation. Therefore, sub-transmission planning needs to be coordinated with the siting, capacity planning, and scheduling of substations (which of course has to be coordinated with distribution system planning, as shown in Figure 13.10). This coordination involves planning and scheduling of the sub-transmission and substation levels in which the cost impacts among the levels are “traded” back and forth. In many utilities, all these functions are combined into one “sub-transmission level” planning process. Given that this is coordinated well with distribution planning, it is a good approach.

Table 13.8 summarizes the important elements of this part of the sub-transmission planning process.

Table 13.8 Sub-Transmission Planning

Substation Planning

In many ways, the substation level is the most important level of the system for two reasons. To a great extent this level fashions the character of the whole system. Substations are where the transmission and the primary feeder levels meet, the points to which the sub-transmission must deliver power, and from which the feeders must take it to neighborhoods throughout the system. The substation levels defines how and where cost, contingency, or capacity at one level can be traded or played against the other, and how expansion of both can be coordinated.

The substations’ sites set very definite constraints on the design and routing of the transmission and distribution systems - transmission lines must “end” at the substations and feeders must begin there. Substation location heavily impacts the cost and performance, and particularly the available design freedom, at both T and D levels. Substation capacity limits also heavily influence both transmission (how much incoming capacity is needed) and distribution (what amount of power can be distributed out of a substation).

As a result, regardless of whether substation planning is done as a separate planning function (about 20% of utilities), or as part of transmission planning (60%), or as part of distribution planning (20%), it should be interactively coordinated with both sub-transmission and feeder system planning. This means that communication should be explicit and frequent enough that glaring differences in marginal costs of expansion at the T, S, or D levels will come to the attention of the planning establishment in the utility and be dealt with by appropriate changes to the plan.

Figure 13.11 Residential and commercial growth in the shaded area is expected to add 31 MVA over the next decade. Either Edgewood or Kerr substation could be expanded at about the same cost to serve this growth. However, expanding the feeder system out of Kerr would be expensive - present feeder getaways are saturated, the system is underground and many duct banks are congested, and several geographic barriers make feeder runs quite lengthy. By contrast Edgewood’s all-overhead feeder system would be straightforward to expand, costing $1,900,000 less. Despite this, the overall optimal alternative is to expand Kerr, because transmission limitations at Edgewood would cost more to overcome than their savings at the distribution level.

For example, in Figure 13.11 distribution planners have made plans to expand Edgewood substation from 55 to 90 MVA capacity in order to serve a peak load that is expected to grow from 49 to 80 MVA due to load growth in the area indicated. Both Kerr and Edgewood substations are close enough to the load growth to pick up this new load, and either could be expanded with roughly the same plan and cost - addition of another 27 MVA transformer and associated equipment, at a cost of $750,000 PW.

However, from the perspective of the distribution system, expanding the feeder system out of Kerr substation instead of Edgewood would cost an extra $1,900,000 PW. Thus, Distribution Planning selected Edgewood for addition of new feeders and equipment to serve the load growth. But suppose that expanding transmission delivery capability at Edgewood by the required 31 MVA will require extensive reinforcement of towers and conductor, at a cost of $2,600,000 PW, whereas the changes needed at Kerr to accommodate a similar increase in peak load are minor and would run only $325,000 PW. Then it is best for the utility to decide to serve the new load out of Kerr, since even though Edgewood is the least expensive distribution option, when overall T-S-D cost is considered, it comes to $600,000 PW less to serve the load growth from Kerr.

The planning process at many utilities can not accommodate this very simple, common sense approach to cost minimization. The procedural “hand-offs” between transmission, substation, and distribution planning groups does not convey enough information, nor allow for sufficient back-and-forth cooperative communication, so that cost differences like this are noted and the planning process can recognize if and how to adjust to them. At many utilities, the distribution planners will pass no details other than the projected total load for a substation - “We need 80 MVA delivered to Edgewood.” At others the reverse happens, with transmission planners setting limits on substation capacity due to transmission constraints, without information of whether these could be eased if economically justifiable based on distribution costs.

Substation planning is important chiefly because of this requirement, that as the meeting place of transmission and distribution it defines their cost interaction. Planning procedures at this level ought to reflect this relationship and foster the required communication. There are at least three possible avenues to do so.

1. Planning meetings between transmission and distribution planning can be scheduled frequently and set up so that a free exchange of planning details, not just planning results, occurs. The authors are well aware of the institutional barriers that exist within many large utilities to this type of communication. In the case of one large investor-owned utility, the managers of the transmission and distribution groups, both of whom had been in their positions for over four years, had never met and had exchanged only a handful of formal “form reports” during their respective tenures. Under deregulation, there could well be formal procedures defining the limits of and requiring such cooperation. Regardless, the results of such communication are significant savings, and worth considerable cultural adjustment. Situations like the Kerr-Edgewood example occur more often than is recognized.

2. Use of methods and software for the sub-transmission, substation, and distribution planning functions that accepts marginal or incremental cost data for the other level, or for the substation level that accepts such data for both. For example, some service-area based optimization algorithms applied to substation-distribution system planning can accept transmission system cost curves for incoming capacity, cost which is included in the optimization.

3. A system of common planning procedures and nomenclature that sets typical target values for every level of the system and reports the incremental cost of all projects at any level, to all planners at other levels in routine, periodic reports. This would pass on to all the distribution, substation, and sub-transmission planners information for their use on the costs at other levels of the system. This provides the information, but not the incentive, for cooperation.

Table 13.9 Substation Planning

Frankly, application of all three of the above measures is best so as to lead to the most coordinated planning, which will minimize the potential for planning errors. Table 13.9 summarizes substation planning.

Feeder Planning

There are two very different aspects of “feeder planning.” The first is feeder system planning (Table 13.10), which involves the planning of the overall distribution feeder system in conjunction with the substations. The second, feeder planning, which involves the detailed layout of feeders and their specification is to a detailed engineering level of itemization and precision (Table 13.11).

Feeder System Planning is a Key Element of Reliability Planning for Aging Infrastructures

Chapter 8 highlighted the need to use the feeder system to provide load transfers and contingency ties between substations. Feeder system planning, aimed at making certain that sets of feeders associated with each substation can accomplish the required target levels for transfers under normal and contingency situations, is essential to assure dependable backup capacity in an integrated T&D system plan. Overall policy decisions on what type of switching support to have both within each substation area, and for transfer of loads between substation areas, is a multi-feeder design aspect. While some single-feeder planning has to be done as a follow-up to the decisions made at this stage, assurance of reliability via good contingency withstand and support capability at the feeder level is done on a system basis.

Figure 13.12 Multi-feeder system planning evaluates the performance of the entire feeder system associated with a set of substations. Its goal is to capture completely the interaction of substation level and feeder level constraints and costs to determine the overall substation-feeder optimum. A big part of this boils down to assigning “optimal service areas” to all substations while acknowledging capital and operating costs and electrical and geographic constraints at both the substation and feeder levels simultaneously, while determining the boundaries (dotted lines) between the substations.

Customer-Level Planning

Traditional supply-side-only planning, through the first three quarters of the 20th century, included very little if any “customer-level” planning functions. Regulated utility IRP (integrated resource planning) of the type widely practiced in the late 1980s and early 1990s included a great deal of customer side measures to control load and efficiency - various DSM (demand side management) options were optimized on some type of societal resource-value basis, (see Willis and Rackliffe, 1994).

In the 21st century, “DSM” has expanded to include not just load-related adjustments and energy efficiency measures, but customer-owned generation and energy storage. It also includes much more emphasis on free-market driven incentives. Programs and policies in the 20th century envisioned utility control of load reductions. Their equivalents in the 21st century envision customer control and choice responding to real time and other market-driven incentives. Regardless, it appears almost certain that IRP will become the mainstream, expected approach for the industry.

For this reason, “customer-level planning” along with full consideration of customer-side resources and customer operation of them, can be expected to be an aspect in all power delivery planning. Table 13.12 summarizes key points in planning at the customer level. The interaction may be much more than just oblique, because customer actions with regard to load reduction, load scheduling, energy efficiency improvements, renewable generation, and energy storage can have a very substantial impact on T&D, since they affect the demand, the energy use, and the reliability needs the system must meet.

Customer-level planning often has a very long planning period, much longer than distribution planning, and often as long as that of generation. There are four reasons why both its short- and long-range planning periods are longer than almost all other levels of the system:

1. Lead time. While DSM programs can often be approved and implemented nearly immediately, it can take years of slow progress to obtain meaningful levels of participation - rates of 50% may take a decade or more to obtain. This “ramp up time” has the same effect as a long lead time.

2. Customer commitments. In starting a DSM program, a utility is beginning a very visible customer-interaction. Such programs are not entered into lightly and are often studied over the very long term to make certain the utility can feel confident it will commit to them for the long-term. Starting such a program and then canceling it several years later is not only costly, but leads to customer confusion and lack of confidence in the utility.

3. Proxy for generation. Customer side resources are often traded against generation in integrated resource planning. Comparison of the two resources needs to be done over the time span used for planning of generation, which means a present-worth or similar economic comparison over a 20-to-30 year period.

4. Uncertainty of resource. Even when the utility has absolute control of major customer loads such as space heating and cooling, there is still a small modicum of uncertainty about the available load reduction at any time, due to the variation in loads that might be on at that time. Taking such DSM measures, and the uncertainty in them fully into account is a normal part of good power delivery and energy resource planning and designing systems to achieve performance goals such as SAIFI targets and voltage regulation criteria.

But there is much more uncertainty about the availability of the customer side resources in an industry where the utility’s customers can respond to real-time price signals, and can or cannot operate their generation and storage as they see fit. Customers may or may not maintain their renewable generation over time. They may prefer to operate it differently than the utility expects. At peak periods customers will probably respond to price signals as expected, but perhaps they will not if it is an unusual situation. Even customers who originally buy energy storage systems as a reliability augmentation resource may begin using them, over time, to reduce cost/earn money via daily arbitraging of energy prices, changing the pattern of customer response the utility grew used to seeing on a daily basis.

Planners simply do not know the details of these customer-side response issues with the specificity that they know, say, the expected capacity of a feeder or a utility owned DG unit. That uncertainty needs to be taken into account in their planning of the delivery system’s capability and performance. It means achievement of traditional SAIFI targets, voltage regulation, and loading guidelines faces much more volatility. Where to put “a stake in the ground” with respect to the needed amount of power delivery capability is much more difficult.

Here, important aspects of regulatory policy and industry expectations have not yet been fully identified. Since the utility’s customers are now resource owners and operators, they can be viewed as partly responsible for performance lapses in the system’s ability to satisfy their energy needs. Does a customer who owns an energy storage system capable of powering his home or business for three hours have any right to complain that his lights went out when the local feeder was out of service for two hours? Does a homeowner who fails to maintain her 15 kW of PV panels so they are available during peak demand periods have a right to complain that voltage at her service entrance dropped to 108 volts? One can argue either side of these questions, and people will, because there is validity in some of the arguments on either side. Different solutions set different precedents and have far different implications on costs and benefits, particularly as to how the cost of the entire utility system is allocated to energy users via the utility’s rates. Regardless, eventually, policy and expectations will harden around a set of guidelines and expectations that the industry pretty much follows, but at present they are not yet fully formed. And regardless of what those are and how they are implemented, planning for customer-side performance targets and criteria will need to be done probabilistically, and planning for the attainment of the utility’s own business performance goals and targets will be messier, face more volatility, and require more comprehensive risk-mitigation methods than in the past.

Customer-level planning generally begins by adding more detailed, end-use and customer value attributes to the load forecast - forecasts by end-use and appliance category and of reliability value functions. It then tries to optimize PW cost of providing end-uses to the customers by juggling various DSM and T&D options. Generally, optimization methods function by balancing marginal cost of the various customer-side options against marginal cost curves obtained for the supply side. DSM and DG evaluation may also be part of value-based planning in which the utility and customer value functions are jointly optimized.

Table 13.12 Customer-Level Planning

The Systems Approach Is Important for Aging Infrastructure Planning

The discussion and figure above showed the economic advantages that the systems approach can provide. These are certainly important to all utilities, including those facing aging infrastructure issues. However, there is another, and vital reason to apply the systems approach as a rule in all planning for aging T&D infrastructures:

The systems approach helps work around constraints in siting, size, or topology by drawing on the resources of the other levels in the power system to solve problems present at another.

As mentioned in Chapter 8, very often the owner of the aging T&D system is “stuck” with too few and too small substation sites. Sub-transmission rights of way may be narrow and non-optimal in routing. Expansion and addition may be costly, time consuming, and politically unacceptable.

Regardless, in many cases the utility has little choice but to make the best of these assets, particularly in aging areas of its system where additional land and rights of way are very expensive. The best way to improve performance is to seek out strengths in adjacent levels of the system in order to help support the weakness in another. Techniques discussed in Chapters 10, 11, and 14 can be applied to do just this, as was summarized in Section 13.5. More detailed discussions of the “systems approach” necessary to optimize the synergism among the sub-transmission – substation – feeder system levels to truly maximize the reliability/cost ratio of the entire power system chain are contained in the Willis (2004).