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Beginning in the late 70s and early 80s, electricity utility regulatory systems have introduced a new form of regulation to incentivize firms to maximize efficiency – incentive regulation. Incentive regulation can be defined as how government regulators promote efficiency among electricity providers by offering rewards and penalties based on the level of result the electricity providers achieve.

Compared to the traditional cost-of-service regulation, incentive regulation will grant the firms with a reasonable amount of rewards under the condition they achieve a certain level of efficiency in electricity production. For instance, under the traditional cost-of-service regulation, the firm’s revenue is calculated by adding the operating cost to the capital cost multiplied by the rate of return, as shown in the formula below.

R = (B * r) + E + d + T

  • R – The amount of revenue the firm requires to cover all costs and expenses
  • B – The base rate the firm requires to cover costs of capital and assets utilized to provide service
  • r – Government permitted rate of earnings that scales with the base rate
  • E – The expense amount that the firm spent on supplies and labor to provide service
  • d – The expense amount that the firm spent on its depreciated capital
  • T – Taxes

PBR SimplifiedIn this case, as the firm’s capital cost (base rate) increases, so does their rate of return. For incentive regulation or performance-based regulation (PBR), a new element is added to the calculation of the revenue – rewards based on performance. In this form of regulation, the firm’s profit is no longer solely dependent upon the rate of return based on the capital costs, but also affected by the utility’s performance. Hence, as the utility’s performance improves, the firm will receive some level of rewards added to their revenue. Firms displaying poor performance will be subjected to a fee or fine, which will decrease their profit. This greatly weakens the link between the utility’s price and the utility’s cost of service.

Incentive regulation can be categorized into two main classes:

  • Targeted Plans
  • General Plans

Targeted plans will introduce the incentive regulation via a specific cost area that is of concern, such as energy efficiency spending and sales on the wholesale market. General plans, on the other hand, link the firm’s earning to the measure of performance in a particular area, such as safety, customer satisfaction, or service quality. Both of these types of regulations are focused on addressing a particular area of concern and incentivize firms to improve the performance or operation in that particular aspect. Common forms of incentive regulatory plans include:

  • Earning Sharing
  • Price Caps

An earning sharing mechanism tracks the actual earnings reported. If over a targeted level set by the government regulators, then these earnings will be shared by the shareholders and their customers. This form of regulation encourages firms to cut spending and expenses and improve efficiency and operation costs to achieve the targeted levels to improve their own returns.

A price cap is a form of incentive regulation where a benchmark is determined to reflect changes in price as a result of inflation and other factors. The general formula used to calculate the price would be multiplying the old price by one plus a measure of inflation minus productivity, as displayed below:

Pricing cap advantagePt = Pt-1 * (1 + RPI – X)

  • Pt – Price of the current period
  • Pt-1 – Price of the previous period
  • RPI – The measure of inflation
  • X – Productivity factor

In the formula above, X is the productivity factor that is determined based on the performance of other firms in the industry. Hence, this regulation system provides firms with an incentive for efficiency savings or price drops, whereas anything above the predicted rate of X will be passed on to the shareholders.

Incentive regulation has shown success in cutting the capital costs and deprecation costs of electricity firms. However, it does introduce new risks and challenges. In order to achieve additional cost savings to reach a certain level of performance, firms might take drastic measures to reduce their numbers.  For example, to reach the incentive threshold, many firms reduce their service quality in order to bring down their capital costs. This is a widely recognized problem, where regulators have designed many remedies to prevent service quality deterioration. Regulatory bodies may establish a service quality standard along with the incentive regulation to keep the quality in check.


A market-based rate is the price of a service or product based upon market condition. Traditionally, regulators used formulas to calculate revenue requirements for each firm based on their reports, which included operational expenses, gross value of utility’s tangible or intangible property plus accrued depreciation. In 2015, FERC granted market-based rate authorization for wholesale sales of electric energy, capacity and ancillary services by sellers that can demonstrate that they and their affiliates lack or have adequately mitigated horizontal and vertical market power.

In order to obtain market-based rate authority, the seller needs to submit two studies:

  • Pivotal Supplier Screen
  • Market Share Screen

If the seller does not pass both screens and the seller still wants market-based rate authority, the seller needs to submit a more detailed delivered price test (DPT). Failure of the DPT requires the seller to provide mitigation for its market power.

Metrics of the Market-Based Rate Authority Evaluation Process:

  • Graph with Pivotal Supply Screen
  • Market Share Screen, DPT
  • Mitigation for its Market Power

Pivotal Supplier Screen Process (Peak Supply Test)

According to FERC Order No. 697 (2007), “the second screen is the pivotal supplier screen, which evaluates the potential of a seller to exercise market power based on uncommitted capacity at the time of the balancing authority area’s annual peak demand. This screen focuses on the seller’s ability to exercise market power unilaterally. It examines whether the market demand can be met absent the seller during peak times. A seller is pivotal if demand cannot be met without some contribution of supply by the seller or its affiliates.”

Definition of Terms:

  • Total Uncommitted Capacity = Total Capacity-(Native Load + Operating Reserves + Long-term Sales) + Uncommitted Capacity imported into the relevant market.
  • Balancing Authority Area (BAA): The collection of generation, transmission, and loads within the metered boundaries of the balancing authority. The balancing authority maintains load resource balance within this area.
  • Wholesale Load at Peak: The annual peak in the relevant market minus the average daily peaks of load during the month of annual peak.
  • Net Uncommitted Supply = Total Uncommitted Capacity – Wholesale Load at Peak
  • Seller Uncommitted Supply < Net Uncommitted Supply

Wholesale Market Screen (Energy Supply Test)

The wholesale market screen compares the megawatts of uncommitted capacity owned or controlled by the seller to the uncommitted capacity of the entire relevant market for each of four seasons.

Metrics are similar to pivotal supply screen:

  • Applied to all seasons, both on-peak and off-peak periods
  • Allows for planned outage in each season

A threshold of 20% market share cannot be exceeded.

If the seller passes both indicative screens, a rebuttable presumption that the seller does not have significant horizontal market power is established.  Failure in either screen will lead seller to perform delivered price test.

Delivered Price Test (DPT)

DPT consists of three parts:

  • Pivotal Supplier Screen
  • Wholesale Market Screen
  • The Herfindahl-Hirschman Index (HHI)

FERC will use certain technical modifications in the implementation of the two indicative screens again. For HHI under DPT model, FERC adopts a threshold of 2,500 as a measurement of market share concentration that gives rise to market power concerns.

Mitigation Methods

If FERC still has concerns about a market-based rate applicant’s market power after performing the delivered price test, it allows the seller to propose a cost-based mitigation method. FERC will provide a default list of mitigation methods:

  • Sell at cost-base rate
  • Reduce supply via long-term contract for capacity and energy

Case Study:

FERC revoked authorization for Berkshire Hathaway Energy subsidiaries to sell wholesale power at market-based rates in four neighboring balancing authority areas in the West in June 2016 due to the fact that Berkshire failed to prove its affiliates do not exercise horizontal market power.

FERC ordered the companies to file revised tariffs limiting their market-based sales to regions outside the four areas within 30 days. The companies must also issue refunds for the period between January 9, 2015 and April 9, 2016.


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A rate case is a formal process, conducted by utility regulators, to determine if the utility’s proposed base rates are just and reasonable. The process starts with the utility company filing an application and testimony with the utilities commission. This application includes the total costs to serve customers and the justification as to why current rates are no longer sufficient.


Electric utilities typically need to adjust rates when costs have risen and the revenues collected no longer cover the cost of building, operating, and maintaining the system. A rate case review process is initiated when an investor-owned utility applies to its regulator for a rate or policy change. Most utilities file for general rate increases every two to five years, though in some instances, utilities have gone more than ten years without a general rate case.

Some states require a general rate case on a fixed schedule, but most do not. The commission normally has the authority to initiate a rate review on its own motion, but this is also a rarity. In theory, an individual consumer submitting a formal complaint that the utility’s rates were not in compliance with the requirements of law (which generally state that rates should be “fair, just, and reasonable”) can also trigger a general rate review, but this almost never happens.


A typical timeline for a rate case, according to the New York State Department of Public Service, is shown below:

Months 1-4: The Department of Public Service provides a staff team charged with the responsibility to analyze the utility rate filing and represent the public interest. The team includes lawyers, accountants, engineers, economists, financial analysts, and consumer service specialists who audit and investigate the company’s proposals. The team typically develops an opposing position and counter-proposal to the rate filing. Other interested groups can also file testimony and challenge the utility rate filing. An Administrative Law Judge is assigned to preside over the case, hear all the evidence, and provide recommendations to the PSC.

Months 5-7: The testimony filed by staff and other interested groups are received, rebuttal testimony by utility company is allowed, and hearings with cross-examination of all expert witnesses are conducted. Groups participating in the rate case may negotiate a settlement of the issues and submit it to the administrative law judge for review.

Months 7-9: Initial and reply briefs are filed with the administrative law judge; administrative law judges may issue a recommended decision. Public statement hearings are held in affected service territories.

Months 9-11: Additional briefs are filed with the PSC. Commission deliberations are held in open and public meetings and a written order is issued resolving all outstanding issues and matters necessary to determine the utility company’s revenue requirements and the amounts to charge customers.

Rate case procedure steps4.3.4 WHAT ARE THE PROCEDURAL STEPS IN A RATE CASE?

The procedural steps for a rate case are shown in the chart to the right.

The detailed steps in a rate case are:

  • The first step before a utility can change rates is to submit an official request to the respective public service commission.
  • The respective commission staff audits the request and supporting documentation.
  • Other parties, known as interveners, may perform additional audits and reviews, voicing concerns or requesting more information to better understand the utility filing.
  • The commission invites customers and the public to ask questions or express comments about the requested change.
  • The utility formally presents the case to the commission through testimony. Commission staff and interveners also file their case through testimony.
  • The utility provides the most current numbers and final facts for consideration.
  • The utility works with all parties to resolve as many issues as possible. The commission hears any unresolved issues in a formal hearing. Commissioners then review any agreements, testimonies and documentation presented.
  • The commission issues a formal ruling and announces approved rates, which are then integrated into customer billing.


Below is the basic formula used by the regulatory commission.

Revenue Requirement = Expenses + (Rate Base x Cost of Capital)

Revenue requirement is the money needed to cover costs. Costs include a fair return to investors. The calculated revenue requirement is compared to the revenue under existing rates to decide if a base rate increase or decrease is needed.

Expenses include operating and maintenance costs, depreciation and amortization on assets, income, and general tax expenses.

Rate base, representing investor supplied capital, is made up of plants in service – net of depreciation to date – and working capital less deferred income tax and other miscellaneous adjustments.

Cost of capital includes the cost of debt or the average interest rate paid on outstanding debt. It also includes the cost of equity – the return an investor expects to receive when they buy stock. That return includes dividends and growth in stock value. The total revenue requirement can be distributed across customer groups, including residential, industrial and commercial, based on the cost of service for that group.

Alongside the above formula, several other points are factored in while coming up an appropriate rate value:

  • Interstate System Allocation – When a utility serves more than one state, the commission conducting the proceeding must decide which facilities serve its state. Identifying distribution facilities and expenses is fairly straightforward, because they are located in specific states and serve only customers in that state. The more complicated part of the problem is allocating a utility’s costs for administrative headquarters, production, and transmission investments and expenses. In the case of some multi-state utility holding companies, FERC determines the allocation of generation and transmission costs between jurisdictions. Commissions split production and transmission costs – including the investment in generating facilities and transmission lines, the operating costs of those facilities, and payments made to others for either power or transmission – based on various measures of usage.
  • Regulated vs. Non-Regulated Services – Many utilities are also part of larger corporations that engage in both regulated utility operations and non-regulated businesses, which may or may not be energy-related. In these cases, the commission needs to determine the allocation requirement for the specific company and location. It also needs to determine what part of the costs will go to expenses for officers and the board of directors, for corporate liability insurance, and for headquarters facilities. Non-regulated operations are typically riskier business ventures, and the commission must carefully allocate the costs so that utility consumers do not bear these risks. Allocation of these costs requires an assessment of relative risks and relative benefits and can become highly contested.
  • Gas vs. Electric – The commission also needs to segregate revenue and operational expenses for utilities that provide both gas and electric service, so that electric rates cover only the costs of providing electric service and gas rates only those of gas service. Formulas that are typically used for dividing the shared costs will consider the numbers of customers, the amount of plant investment directly associated with each service, the labor expenses associated with each service, and the total revenue provided by each service.


The key players in a rate case are the:

  • Utility company
  • Commission staff
  • Consumer advocate

Other participants or interveners, such as representatives of industrial consumers, low-income consumers, and environmental groups are granted the right to participate by the commission, sometimes after demonstrating a particularized interest that is not better represented by the statutory parties. A federal law, the Public Utility Regulatory Policies Act (PURPA), gives consumers of large electric utilities a statutory right to intervene in any rate-related proceeding pertaining to standards addressed in PURPA.


The general population can participate in the regulatory rule making process via many avenues. While some opportunities are complex and legalistic, others are simple.  Various forums give consumers, environmental advocates, business groups, and others the opportunity to participate in the regulation of utility prices, policies, and resource planning.

  • Rulemaking – Commissions make two types of rules. Procedural rules guide how the regulatory process works. Operational rules govern how utilities must offer service to consumers. Normally the public is given an opportunity to comment when rules are proposed or amended.
  • Intervention in Regulatory Proceedings – Intervention in a formal regulatory proceeding is probably the most demanding form of citizen participation. Utility hearings are normally held under state administrative law rules and function very much like a courtroom. While an individual may usually participate without an attorney, requirements of the rules of procedure and evidence must still be met.
  • Stakeholder Collaboratives – In the past decade or so, many commissions have formed stakeholder collaboratives to engage utilities, state agencies, customer group representatives, environmental groups, and others in a less formal process aimed at achieving some degree of consensus on dealing with a major issue. These collaboratives may meet for a few months or more, then collectively recommend a change to regulations, tariffs, or policies.
  • Public Hearings – Utility regulators hold two types of public hearings. When a rate case is underway, the entire process of cross-examination of witnesses is generally called a public hearing, but is usually a very technical process not really designed for public involvement. In addition, regulators often hold public hearings on matters pending before the commission in a policy investigation or rulemaking context. Public hearings of this type offer the commission an opportunity to hear opinions of the public on the particular issue.

US Investor owned electric utilities4.3.8 RATE CASE BY NUMBERS

From 1997 to 2002, on average, approximately five rate cases were filed per quarter with state regulators. Since 2006 that figure has been roughly thirteen per quarter. In the first quarter of 2016, investor-owned electric utilities filed fourteen new rate cases. The primary reason for rate case filings is capital expenditures followed by utilities’ desire to implement rate mechanisms that allow for cost recovery between rate cases. A third was companies’ desire to enhance return on equity.

The graph to the right shows the number of rate cases filed quarterly by IOUs.



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4.2.1 FERC

In 1920, Congress established the Federal Power Commission (FPC) to coordinate hydroelectric projects under federal control. At first, FPC could only employ an executive secretary and borrow all other personnel from different administrating executive departments. The organizational structure caused conflicting interests among different departments, making it difficult to produce consistent energy policies. As a result, Congress voted to grant funds to permanently hire staff for FPC. After years of expansion and consolidation among regulating agencies, FPC was renamed the Federal Energy Regulatory Commission (FERC).

The Federal Energy Regulatory Commission (FERC) is an independent regulatory agency within the United States Department of Energy with five members appointed by the President and confirmed by the Senate. Congress granted FERC power under the Federal Power Act, the Natural Gas Act, and the Interstate Commerce Act to regulate the Wholesale Retail Chartinterstate transmission of electricity, natural gas and oil. FERC’s responsibilities also include review of proposals to build interstate natural gas pipelines, natural gas storage facilities, liquefied natural gas terminals and licensing of non-federal hydropower dams. Within the electricity industry, FERC regulates wholesale sales of electricity and transmission of electricity in interstate commerce, oversees mandatory reliability standards for the bulk power system, promotes strong national energy infrastructure, regulates jurisdictional issuance of stock and debt securities, assumptions of obligations, and liabilities and mergers.

For many years, policy makers have been trying to foster competition in wholesale power markets. Over the last few decades, Congress has acted to open up the wholesale electric power market by supporting the entry of new generators to compete with traditional utilities. In 1992, the President signed the Energy Policy Act of 1992 into law to encourage competition in the wholesale energy markets through open access to transmission facilities. The core responsibility FERC has on the wholesale market is to protect consumers from electricity monopolies and ensure customers are charged a reasonable and sustainable rate.

Besides introducing competition into wholesale power markets, FERC also grants market-based rate authorization for wholesale sales of electricity, capacity, and other services to better regulate the electricity market. Wholesale, market-based rate authorizations are granted to sellers that can demonstrate they lack or have mitigated horizontal and vertical market power. Order No. 697 sets the basis in market-based rate consideration. Horizontal and vertical market power analyses are defined under Order No. 697.

Horizontal Market Power Analysis

In order to evaluate horizontal market power, FERC applies two screenings: the market share screening and the pivotal supplier screening. If an applicant passes both screenings, the applicant is considered not to have significant horizontal market power. Failure to pass either of the two screenings will lead to further screening to determine a ruling on the application.

Vertical Market Power Analysis

While evaluating vertical market power, FERC has specified any concern regarding vertical market power should be addressed in an open access transmission tariff proceeding, not a market-based rate proceeding. The approval of an open access transmission tariff by FERC adequately mitigates vertical market power. If a violation of the open access transmission tariff is found and the violation is related to market-based rate authorization, FERC will revoke the authorized market-based rate from the responsible entity.

In addition to these tasks, FERC is also responsible for facilitating demand responses, overseeing the reliability of electricity providers, promoting transmission investment, and evaluating mergers and corporate transactions.

4.2.2 NERC

While Congress created FERC for the utility industry, the industry created its own regulating organization back in 1968 – the North American Electric Reliability Corporation (NERC). NERC is a not-for-profit corporation formed by representatives in the electric utility industry and is considered self-regulatory. The term self-regulatory is used when a government has given a non-governmental agency the power to make decisions in regulation, while reserving the right and power to oversee any proposals and changes. The general approach to such organizational partnerships often works well as the industry experts can provide more direct, in-depth knowledge of the matter at hand. In the case of NERC and FERC, the utility experts in NERC can provide insight into operational and technical needs of the electric industry that drive new standards and programs. Meanwhile, FERC can continue to ensure that federal regulations are met.

NERC serves very similar purposes as FERC, but specifically for bulk power and electricity systems. The bulk power system is defined by NERC as “the electricity power generation facilities combined with the high-voltage transmission system.” That is, NERC looks to improve the reliability and security of the creation and transmission of electricity on a high infrastructural level, outside of local electricity facilities that may be placed in cities and towns.

With the introduction of the Energy Policy Act of 2005, FERC assigned NERC to be the Electric Reliability Organization of the USA, and henceforth NERC has the authority to create mandatory standards in the industry.

NERC’s methodology addresses different issues to achieve its goals in the bulk power system:

  • Develop and enforce new standards for reliability
  • Provide assurance to all parties in the electric industry, including private and public entities
  • Promote education and propagate industry knowledge across regions in various levels of industry personnel
  • Prioritize new initiatives and attention in the industry by analyzing the risk and forecasting the reliability of the bulk power system

As suggested by the name, NERC provides coverage in North America – including the USA, Canada, and parts of Mexico. The governing body in the USA is FERC; provincial NERC Regional Entitiesgovernments oversee the regions in Canada. More recently, in July of 2016, NERC has expanded its involvement to Europe by signing an administrative agreement with the European Commission’s Directorate General (DG) for Energy. The agreement holds the common reliability interests of NERC and DG energy and encourages collaboration between the organizations as similar challenges emerge throughout the industry.

On a smaller scale, the NERC coverage in North America can be categorized into 8 regional entities:

  • Florida Reliability Coordinating Council (FRCC)
  • Midwest Reliability Organization (MRO)
  • Northeast Power Coordinating Council (NPCC)
  • Reliability First (RF)
  • SERC Reliability Corporation (SERC)
  • Southwest Power Pool, RE (SPP RE)
  • Texas Reliability Entity (Texas RE)
  • Western Electricity Coordinating Council (WECC)

The regional entities above provide virtually all electricity to North America. Each entity shares a common theme in that NERC delegates authority and responsibility to their region. We will discuss one of the regions, Western Electricity Coordinating Council below.

Western Interconnection4.2.3 WECC

The Western Interconnection is an electricity grid on the western side of the Americas stretching from Canada, through United States, and to the northern parts of Mexico. NERC has delegated authority to the Western Electricity Coordinating Council (WECC) to create, monitor, and enforce reliability for the Western Interconnection; it is the largest regional entity under NERC.

WECC serves similar purposes as NERC. Its mission statement is to “promote and foster a reliable and efficient Bulk Electric System.” WECC is also a non-profit corporation.

WECC currently has 5 major program areas:

  • Compliance and Monitoring and Enforcement Program – this program monitors and enforces compliance and is separated by smaller regions, as they need to be approved by different governing bodies in Canada, the USA, and Mexico.
  • Reliability Planning and Performance Analysis – WECC performs a number of studies and assessments in the Western Interconnection for the bulk power system. These studies include identifying future requirements for the generation and transmission system, load research on the network, and addresses the possible concerns through long-term planning.
  • Development of Standards – On a high level, WECC participates in the NERC Reliability Standards Development process. On its regional level, WECC develops and proposes WECC Regional Criteria for the Western Interconnection. In the development of its regional standards, WECC brings in subject-matter experts on the local grid.
  • Training, Education and Operator Certification Program Area – WECC is involved in organizing lectures that provide information on WECC’s products, services, and processes. WECC also provides technical and industrial training to various industry roles.

Western Renewable Energy Generation Information System (WREGIS) – this is an independent system that operates in regions under WECC. WREGIS is used to keep track of renewable energy generation as part of the green energy initiative.


State regulations in the electric industry are governed by entities known as state public service commissions, and each state commissioner is a member of the National Association of Regulatory Utility Commissioners (NARUC). NARUC is a non-profit organization that represents the common interests of state commissioners, such as providing safe, reliable utility services at reasonable rates. The existence of NARUC ensures that certain standards must be followed by members so that public utility regulations meet the requirements to serve consumers fairly and reasonably.


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Regulation in the utility industry refers to the rules created by government or local bodies which the utility companies must adhere to by law.

Electric utilities are regulated by state, federal, and local agencies. These agencies govern the prices they charge, the terms of their service to consumers, their budgets and construction plans, and their programs for energy efficiency and other services.

US map for regulation and deregulation4.1.1 REGULATED VS DEREGULATED MARKET

Regulated markets feature vertically-integrated utilities that own or control the entire flow of electricity from generation to meter. Examples in the U.S. include Florida, Colorado, Idaho, and Kentucky. Conversely, utilities in deregulated markets must divest all ownership in generation and transmission and are only responsible for:

  • Distribution, operations, and maintenance from the interconnection at the grid to the meter
  • Billing the ratepayer
  • Acting as the Provider of Last Resort (POLR)

Deregulated markets feature grid operators that administer wholesale markets to ensure reliability on the grid and prevent blackouts. Multiple retail suppliers – or load serving entities, known as LSEs – buy generation and sell electricity to end users.

To the right is the USA map showing where electricity is regulated and where it is not.


For most businesses, the free market sets prices for products or services based on supply and demand. This open market provides companies the opportunity to provide a product or service and, if successful, earn a profit depending on costs, quality, and market factors.

Originally, that’s also how it worked for electric utility companies. When the industry was born, inventors and investors could request franchises to create electric companies with few barriers to market entry. Many did and competition determined the rate the customer would pay, however disorganization was a major issue. Lines and poles from multiple companies occupied the same streets, service was unreliable, and grids weren’t interconnected. It was inefficient and, at times, dangerous. This eventually led to the creation of state commissions to regulate electric utilities.


The primary reason for regulation is that all utilities are natural monopolies, meaning that a single provider is often able to serve the overall demand in a region at a lower total cost than any combination of smaller entities. In absence of any competition among the service providers to set lower rates, the service provider might restrict output and set prices at levels higher than are economically justified. Regulation serves the function of ensuring that price structures are followed, that service is adequate, that companies are responsive to consumer needs, and that things like new service orders and billing questions are handled responsively.

Another reason for regulation is that the utilities must adhere to strict government safety standards, because their infrastructure runs throughout our communities and the public would be affected by sagging wires, ruptured pipes, and other problems.

The production and distribution of electricity also has environmental and public health impacts —  through the emission of pollutants, use of land, and even creation of noise — that can adversely affect the public. Generating power often produces pollution; transmission lines have both visual and physical impacts on land use. Regulators may therefore impose environmental responsibilities on utilities to protect these public interests.

Finally, given utilities’ crucial role in the economy and in society’s general welfare, service reliability standards are often imposed.

The electricity industry remains one of the most highly regulated in the United States. It is regulated on both federal and state levels. Sometimes, local regulations also apply. Rules and regulations can provide protection for consumers, help keep workers safe, ensure businesses do not collude to raise prices, etc. However, some argue that too much regulation of markets is unnecessary and can lead to inefficiencies and unnecessary costs.


A range of federal, state and local level entities regulate the U.S. electricity sector. They are:

  • Federal Energy Regulatory Commission (FERC), which regulates interstate electricity sales, wholesale electric rates, and hydroelectric facility licensing, among other energy matters affecting interstate commerce
  • Environmental Protection Agency (EPA), which regulates certain emissions from power-generating facilities
  • North American Electric Reliability Corporation (NERC), under FERC oversight, which ensures that the bulk electricity system in North America is reliable, adequate, and secure
  • Nuclear Regulatory Commission (NRC), which oversees the safety and licensing of nuclear power plants
  • Department of Energy (DOE), which is responsible for promoting energy security as well as scientific and technological innovation

Other relevant entities, but ones that are typically less directly involved in day-to-day electricity sector regulation, include:

  • Commodity Futures Trading Commission (CFTC), which regulates certain commodity trades, including power hedges, and trade options
  • Department of Justice (DOJ) and the Federal Trade Commission (FTC), which enforce anti-trust laws
  • Securities and Exchange Commission (SEC), which regulates the issuance of corporate securities from energy companies, among other things
  • Occupational Safety and Health Administration (OSHA), which regulates safety standards for certain power facilities


Almost all regulatory authorities perform the same basic functions:

  • Determining the revenue requirement
  • Allocating costs among customer classes
  • Designing price structures and price levels that will collect the allowed revenues, while providing appropriate price signals to customers
  • Setting service quality standards and consumer protection requirements
  • Overseeing the financial responsibilities of the utility, including reviewing and approving utility capital investments and long-term planning

Serving as the arbiter of disputes between consumers and the utility.

Federal Energy Regulatory Commission4.1.6 COMMISSION STRUCTURE AND ORGANIZATION

Most state commissions consist of three or five appointed or elected commissioners and a professional staff. Shown here is the organizational chart for FERC.

As an example, the Public Utilities Commission of Ohio (PUCO) lists their organization and their tasks as below on their website:

  • Administration – The Office of Administration provides internal support, including docketing, necessary for the day-to-day operations of the agency.
  • Attorney General – The Attorney General’s public utilities section represents the PUCO staff before the Commission and represents the Commission itself before the Supreme Court of Ohio, other state and federal courts, and federal administrative agencies.
  • Business Resources – The Business Resources Department includes the Human Resources division, the Fiscal and Office Services division, and the Information Technology division.
  • Commission Offices – The Commission Offices include the commissioners and their aides.
  • Legal – The legal department’s attorney examiners conduct public hearings, issue procedural entries, and draft the opinions and orders issued by the Commission.
  • Public Affairs – The Office of Public Affairs fosters the PUCO image by communicating utility information to Ohioans in a timely, accurate, and understandable manner.
  • Rates and Analysis – The Rates and Analysis Department conducts independent energy forecast reports, participates in federal and state programs and investigations regarding energy policy, delivery and reliability, monitors and advises on utility conformance with prudent corporate oversight practices and procedures, monitors energy efficiency and portfolio compliance requirements, processes utility rate change requests, and performs technical investigations. The department is comprised of the administration; market and corporate oversight; policy and research; telecom; technology; regulatory services; and siting, efficiency, and renewable divisions.
  • Service Monitoring and Enforcement – The Service Monitoring and Enforcement Department examines the quality of service provided by utility companies to ensure that safe, dependable and quality services are being provided. The department also handles requests for information, complaints, and attempts to resolve consumer problems without the need for a formal hearing.
  • Transportation – The Transportation Department regulates railroad, trucking, bus, and watercraft companies across a broad range of activities.


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Electricity goes through a complex delivery system before the end user is able to consume it. Traditionally, the U.S. uses a vertically integrated monopoly where the utility company is responsible for all aspects of the energy services, from generation to the electric system operations. This utility model could be an investor-owned utility, municipal and public utility district, or a rural electric co-op. Because of the lack of competition, government imposed cost regulations exist to protect the end user. However, the electric marketplace is also evolving, and the once dominating business model of government regulated monopolies is shifting toward a business model that fosters competition. This change will allow for cheaper, more reliable service. It also encourages innovation in the marketplace. Since the market is changing, the set of rules defined by regulators must change as well in order to adapt to this new competitive market.


In contrast to the regulated market where prices are set by regulations, market-based electricity prices fluctuate based on the perception of the supply and demand. These prices are determined in two ways. A common place for short-term transaction is the Intercontinental Exchange (ICE). ICE was founded to facilitate the purchase and sale of energy commodities. For long-term transactions, bilateral trading is a common method to buy and sell energy. Under mutually agreeable terms for a certain period of time, an agreement is created between the willing buyer and willing seller to exchange electricity, rights to generate, etc. These types of arrangements are necessary to create a stable energy market essential to perform long-term planning and optimal investment decisions. A competitive market requires price transparency, which means that all the parties involved have access to the information about the market price at a specific location. To ensure the integrity of these indexes, the Federal Energy Regulatory Commission (FERC) monitors the market and penalizes any entity that manipulates it.

Transportation pie chartLike any marketplace, business activities are dictated by the end user; the utility is no different. To be better served, the utility places the end user into different customer classes.

The main categories include residential, commercial, and industrial. Customers are grouped into categories based on their individual consumption, which will be similar in any one group. A similar rate class which is the price per Kilowatt hours will be applied to each customer category. So why does the unit price differ greatly based on the customer category?  Let’s look at this chart. Notice the consumption of the different customer classes is fairly similar. However, the number of customers per category is dramatically different. As a result, we can conclude that commercial customers consume more than residential customers, and the industrial customers consume the highest amount of energy, which explains why utilities provide electricity at a cheaper rate for higher energy consumers. Since electricity cannot easily be stored, the utilities biggest challenge is to meet customers’ demand throughout the day. It is critical for utilities to understand its customers’ usage patterns to optimize its electric delivery system. In a regulated market, the price of energy is usually stable since they are set by regulations. However, many markets are becoming deregulated. In such markets, the pricing is dictated by the perception of supply and demand.

As mentioned earlier, the vertically integrated monopoly allows the utility to be in control of all the sectors. In a deregulated market, the sectors that could be open to competition are generation, wholesale trading, and retail sales. Retail sales refers to the transaction between the energy supplier and the end user. Since the retail market is open to competition, customers Electricity markets before after deregulationmay choose between the main energy supplier and different competitive suppliers versus a single provider in a regulated market. In a competitive retail market, energy retailers could offer alternative energy sources such as renewable energies, and programs to incentivize customers to switch to more energy efficient supplies. These opportunities allow for customer freedom of choice based on their individual needs and preferences. The retail markets are regulated at the state level, and the public utility commission (PUC) is responsible for regulating the distribution cost, the rate of return for the use, and maintenance of the distribution system. In addition, the PUC is responsible for approving any alternative energy supplier before they are allowed to sell their generated energy.


The utility industry is a good example of a natural monopoly. A large investment is required to produce a unit of output, and larger operations tend to decrease the price per unit. Historically, only few were able to survive the market, or even enter it, which led to an energy industry controlled by monopolies. Regulations were put in place in order to protect consumers from unfair prices. The public utility commission (PUC) was created to regulate the rates and services provided by the utilities. Its main goal is minimizing the cost for its customers, ensuring reliable service, and encouraging innovation within the services provided.

Setting the rates the utility is allowed to charge the end-user requires going through a regulatory process called rate case. By law, this process must be completed within 275 days. The formal process starts with the initial filing, which is usually initiated by a regulated entity. This document describes the reason behind the requested increase. A member of the PUC staff reviews the submitted document and investigates the facts. As part of the investigation, the staff assesses the quality of service provided, reviews the plant infrastructure, the taken safety measures, and the financial records. Following his investigation, the staff files a report that includes his feedback on the rate case. Within thirty days of receiving the rate case judgement, the filing entity is able to file for an objection against the staff’s report if they disagree with the outcome. The commission would then schedule hearings for the case. Its main purpose is to provide all the evidence to support all the parties’ positions. Supporting evidence would include testimonies by witnesses and written documents. After each testimony, the interested parties have the opportunity to argue their case. At the end of the hearing, the administrative law judge or the commissioner drafts an educated decision based on all the facts presented during the hearing. This document is not yet final, and the commission is responsible for making that final decision. In the real world, changes are made to the draft several times based on the different feedback from the commission. The draft decision becomes the final decision once the majority of the commissioners vote to support it. It is important to note that even a final decision could be reviewed by the commission that issued it. If any of the involved parties believe that the decision made does not align with the facts, a request for a review is made either through a petition or a request for a rehearing. The final component of the regulator process is the creation of tariffs. These are a set of rules that define the relationship between the utilities and their customers. These documents are written by the regulated entities and approved by the PUC. They include the terms of services and rates based on each customer class.


Traditionally in the utility market, energy supply is built based on the forecasted demand. Factors such as demographics, customer classes, and the business activities come into play in order to predict the supply and demand. However, it is important to mention that the key driver to increase capacity is to meet the customers’ peak demand. Even though peak demand occurs for only a few hours a day, the utility must meet the market’s peak demand as electricity outages are unacceptable. As part of the movement toward a deregulated market, competition is pushing energy suppliers to find innovative ways to lower the cost. Demand response programs where introduced by utilities to better manage the supply and demand. These programs allow customers to have an active role in the electric grid operation by shifting their energy consumption to a time of the day where the rates are lower.

Because supply and demand change drastically over time, the energy price is very volatile. By lowering the market peak demand, the utility is able to reduce the cost of energy, which in return benefits the end user. Based on the utility’s offerings, customers could participate in different demand response programs. The most popular programs are time-based rate programs:

  • Time-of-Use Pricing: Typically applies a different rate over a few hour blocks. An example would be a higher rate during peak hours.
  • Real-Time Pricing: Usually a supply rate by the hour. Customers subscribed to this program pay the corresponding wholesale hourly market price of electricity. Usually the utility company provides the hourly rate the previous day to allow its customers to determine the best time to use major appliances such as the dishwasher, washer, and dryer.
  • Variable-Peak Pricing: A hybrid of time-of-use and real-time pricing. The different periods for pricing are defined in advance. For example, on peak is defined as six hours for summer weekday afternoons, and off peak is all other hours in the summer months. The price established for the on peak period varies by utility and market conditions.
  • Critical-Peak Pricing: When utilities observe or anticipate high wholesale market prices or power system emergency conditions, they may call critical events during a specified time period (e.g. 3 pm – 6 pm on a hot summer weekday), the price for electricity during these time periods is substantially raised. Two variants of this type of rate design exist: in one, the time and duration of the price increase are predetermined when events are identified, and in the other, the time and duration of the price increase may vary based on the electric grid’s need to have loads reduced.
  • Critical-Peak Rebates: When utilities observe or anticipate high wholesale market prices or power system emergency conditions, they may identify critical events during pre-specified time periods, e.g. 3 pm – 6 pm on summer weekday afternoons. The price for electricity during these time periods remains the same, but the customer is refunded at a single, predetermined value for any reduction in consumption relative to what the utility deemed the customer was expected to consume.

Other programs include:

  • Direct-Load Program: HVAC systems account for a big portion of energy consumption. This type of program allows the utilities to turn on and off certain appliances during peak demand using remote appliance control. Load management saves money for both the utilities and its customers by reducing the energy generation and limiting the amount of energy purchased on the open market during peak periods.

We are witnessing a major shift in the energy industry where certain aspects of the vertically integrated monopoly are becoming obsolete. The energy industry is shifting from centralized electric generation to a more distributed system, where more end users are able to generate their own electricity.


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Electricity retailing is the final component of the electricity delivery process, after generation, transmission, and distribution. It is the final sale of electricity from a provider to the end-use consumer.

The following diagram gives a higher level view of the energy market and how the physical and financial components of the energy sector mesh with one another. As shown above, a consumer, either residential or commercial, buys electricity from a retailer. In turn, the retailer buys electricity in bulk from the wholesale market. Hence, electricity is treated like any other commodity which is bought and sold before being consumed. These transactions are considered “sales for re-sale” and make up the wholesale electricity market.Electricity retailing wholesale and retail

When electricity is purchased from a utility company or a retail electricity provider, this is called retail electricity. Consumers and business are offered a variety of service plans by competitive retail suppliers. These service plans give consumers and businesses flexible energy purchase choices. More choices for alternative energy resources and newer energy efficiency projects may also be offered to help protect against fluctuations in cost. These opportunities allow consumers and businesses to choose the services that best meet their needs.



The chart below, from the US Energy Information Administration, is divided by class and represents the average monthly electric usage for American consumers in 2015.

Average Monthly Consumption (kWh) Average Monthly Bill ($)
Residential 901 114.03
Commercial 6305 670
Industrial 98,391 6,798.62


U.S. states gas and electric suplyThe chart demonstrates that the average monthly consumption for commercial and industrial customers is considerably higher than for residential customers, and, therefore, more lucrative.

Since commercial and industrial customers often need to buy electricity in bulk, electric companies offer different tariffs to them. These tariffs consider variables that are not relevant when supplying electricity for residential usage. With commercial electricity tariffs, business owners can purchase electricity at a lower rate because the large volume they must consume guarantees that electric companies will recuperate their costs.

Some U.S. states offer competitive rates with customer choice programs. Different states have different programs. For example, the Public Utilities Commission of Ohio lets consumers shop for energy options from a diverse group of competitive suppliers.

Regulations and guidelines for energy deregulation or customer choice programs can differ between countries. For example, Europe has created a deregulated energy market with a seamlessly integrated grid. The original 15 EU members all have deregulated energy markets. Once the EU put energy deregulation into place, it started to change the electricity market. European electricity consumers could choose their electricity supplier and create individual supply agreements.

The EU was divided into several different energy regions prior to energy deregulation. This division drove the cost of electricity up for consumers. Now, participating countries have improved their electricity and natural gas grids and have created fully integrated systems across Europe.

Regulated and Deregulated marketsRegardless of the consumers’ choices, residential customers tend to be adequately protected by the federal government, even in deregulated markets. For example, Texas, which has retail competition as a result of a deregulated market, received federal funds to help low-income customers. One organization that helps the elderly, disabled, families with young children, and households with the highest energy costs and lowest incomes is the federally-funded Comprehensive Energy Assistance Program (CEAP), which is federally-funded.

Regardless of whether states allow retail competition, supply for end-use customers is obtained either in the open, competitive wholesale market or from utility-owned, rate-based (cost-plus) generation; sometimes it is obtained from a combination of the two.

Utility rates for consumers are primarily based on:

  1. The base costs of utility service that incorporate the pipes and wires through which service is delivered and the costs of owning and operating power plants.
  2. The costs for fuel and purchased power for electric service (power supply) or gas commodity costs.

Utilities offer several rate structures based on the needs of the consumer.  A residential retail structure may differ based on the type of residence, whereas a commercial retail structure might vary with type of business, e.g. small, seasonal, heavy duty, etc.

Example 1  – Residential: Time-of-use rate structures determine the price of electricity based on what time it is used. Residential tariffs tend to be straightforward and are simply divided by season and time. These prices are lower for people who qualify as low income or have special medical needs.

Deregulation U.S. StatesExample 2 Commercial/Industrial: Commercial and industrial customers have a more complicated rate structure, which includes service fees on their usage and also takes demand into account to calculate electric bills along with other factors like production and transmission charges, distribution charges, substation cost, reactive power charges, line transformer costs, etc.

The above rates and plans can vary from state to state and one of the biggest differentiators is if a state is regulated or deregulated.

Regulation or Regulated State: All processes involved in providing energy, including pricing, are overseen by a regulatory or government body. Only the local utility can sell directly to consumers. The utility or government sets the prices for natural gas and electricity supply, along with the associated transportation and distribution costs associated with those commodities. Consumers are not able to choose their energy provider in a regulated state.

Average rates of deregulattion and regulationDeregulation: Energy prices are not regulated in these areas and consumers are not forced to receive supply from an assigned utility. In deregulated markets, consumers can choose their energy supplier, similar to other common household service providers. In most states providing retail competition, a service called “provider of last resort” (POLR) provides customers who don’t choose a supplier service through their incumbent utility. This is sometimes referred to as standard offer service or SOS.  Deregulated electric utilities are currently allowed in twenty-four states including Ohio, Oklahoma, Oregon, Pennsylvania, Rhode Island, Texas, Virginia, Arizona, Arkansas, and California.

The governing bodies which oversee the retail structure and policies in regulated and deregulated markets are described below.

2.4.2 INDEPENDENT SYSTEM OPERATOR (ISO)Independent systems operators - ISOs

ISOs are formed at the direction or recommendation of the Federal Energy Regulatory Commission (FERC). These organizations coordinate, control, and monitor electrical power system operations and usually operate within a single U.S. state, although they sometimes encompass multiple states. ISOs serve as a marketplace operator in wholesale power. The majority are set up as nonprofit corporations and use governance models approved by FERC and/or regional or local commissions.

ISOs give fair transmission access to allow competition for the benefit of consumers. Also, ISOs provide transaction support and engage in regional planning to make sure the correct infrastructure gets built in the correct place at the correct time.

Seven ISOs currently operate within North America, as shown in the map to the right:


2.4.3 NERC

The North American Electric Reliability Corporation (NERC) is a not-for-profit international regulatory authority that supports the reliability of the bulk power system. NERC has many functions including the development and enforcement of reliability standards, the yearly assessment of seasonal and long‐term reliability, monitoring the bulk power system through system awareness, and educating, training, and certifying industry personnel. NERC’s scope of service includes the continental United States, Canada, and the northern portion of Baja California, Mexico. Users, owners, and operators of the bulk power system, which serves more than 334 million people, are under the jurisdiction of NERC.

The regulation of the interstate transmission of electricity, natural gas, and oil is overseen by the Federal Energy Regulatory Commission (FERC.) The independent agency has many responsibilities within the electric retail market including:

  1. Regulating the transmission and wholesale sales of electricity in interstate commerce.
  2. Reviewing specific mergers, acquisitions and corporate transactions by electricity companies.
  3. Monitoring and investigating energy markets.

One important distinction is that FERC does not regulate the retail electricity sales to consumers; that onus is left on regulatory bodies at the state level.

2.4.5 PUC

Public utilities commissions or public service commissions are  governing bodies that regulate public utilities’ rates and services. These commissions regulate a distribution utility’s costs and rate of return for both the use and upkeep of the distribution system in every state.

In retail choice states, the commissions cannot serve customers until they approve any alternative competitive supplier. The commissions also oversee a POLR or SOS utility’s power procurement and approve the results of the process if it was completed fairly.

In states that do not offer retail competition, commissions regulate the monopoly utilities’ expenditures by allowing a rate of return on most costs.



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The next stage after generating and transmitting electricity is distribution to the consumer. As seen earlier, electricity would have to be stepped up to very high voltages of 44 kV–765 kV for efficiently transmitting electricity over long distances. But, very few practical uses of electricity at this high voltage exist. Electricity would have to be stepped down to 110 V–600 V to be used for common household appliances and 2.4 kV–35kV for commercial and industrial customers.Electricity Distribution This section deals with the various physical components involved in receiving the high voltage electricity from the transmission lines and making it suitable to use for commercial and residential purposes.

The distribution process begins at the distribution substation, shown as section 3 in the figure shown here. The distribution substation receives the high-voltage electricity from the transmission lines and brings down the voltage to 2kV to 35 kV based on the requirements in the service area. Commercial and industrial consumers with high energy demands get electricity directly from the substation. These consumers have distribution transformers set up on their premises to reduce the electricity to the desired voltage needed for their systems. Electricity leaves the substation via feeder lines connected to form a distribution system and reaches the distribution transformers situated close to a consumer’s premise. The consumer then connects to the distribution transformer using a service drop and receives electricity through the meters installed at their location.

Distribution Substation

Distribution SubstationA distribution substation is tasked with the main responsibility of converting transmission level voltages to distribution level voltages. Most substations are also tasked with additional functionalities such as voltage regulation and fault isolation. It is common for companies to rely on SCADA (supervisory control and data acquisition) for remote supervision and control, rather than having manned substations.

Components found in a distribution substation:

  1. Power Transformer (step-down) – A step-down transformer converts transmission voltages to primary distribution voltages (2.4kV-35 kV).
  2. Circuit Breaker – A circuit breaker is used to open and close circuits. These components automatically trip if a short circuit occurs and can also be manually operated.
  3. Surge Arrester – A surge arrester protects the transformer and other electrical components from voltage surges. These are located on either side of a power transformer and are connected at the top to a line conductor and at the bottom to the ground.
  4. Disconnect Switch – A disconnect switch is used to electrically isolate circuits. These are used to ensure worker safety and make maintenance activities possible.
  5. Busbar – A busbar is a large rigid aluminum conductor that links circuits together. It is capable of conducting a substantial current of electricity and is comparable to the working of a distribution panel at home which channels electricity across different circuits.

Distribution Feeder Circuits

A feeder in a distribution network is considered to be the one that occupies the “between space.” These are the connections that leave the distribution substation from a circuit breaker and connect the distribution transformers – near the consumer’s premise on the other end.

Ideally, the voltage across feeder lines is expected to be consistent with the voltage coming out of the distribution substation. However, this is not practical in the real world, causing a noticeable voltage drop. To overcome this problem, feeder lines are often installed with capacitors to accommodate for the loss.

Distribution TransformerDistribution transformer photo

A distribution transformer is the final component in converting the primary distribution power from the feeder lines to low voltage (120V or 240V in most countries) suitable for use with common household electronic items.

Distribution transformers run at 50 – 70% efficiency. Power transformers are much bigger and are used for high voltages (> 33kV) and run at 100% efficiency.

Distribution transformers are usually classified based on their mounting location:

  1. Pole Mount – The transformer is mounted on a utility pole. This is a common sight in older residential neighborhoods and rural areas.
  2. Pad Mount – The transformer is mounted on concrete pads and locked in steel cases. These are more commonly seen in more recently developed areas.

Service Drop and MeterPad Mount

With electricity now in the desired voltage for household consumption, the house or business unit connects to the distribution transformer using a service wire. This service wire is called a service drop.

The service wire is connected to a meter that is installed at every service location through which electricity enters the premises.


A utility might adopt multiple network designs to provide electric service to its customers. The choice of design is a trade-off between the cost and criticality of power supply in that region. The three most common distribution network systems are radial distribution, loop distribution, and interconnected.

Radial Distribution SystemRadial Distribution System

This network topology has one power source for a group of customers. The architecture closely resembles a tree structure where power from a single source radiates out into progressively lower voltage lines until the destination homes and businesses are reached. This is the most common distribution system used in North America and many other parts of the world.


  1. The main advantage of this design is its cost value and simple design


  1. The biggest drawback of this design is the lack of reliability on the network. A problem at a single source or feeder can impact a large number of consumers.
  2. The consumer closest to the power source will be heavily loaded and the consumer farthest away will be subjected to serious voltage fluctuations when the load on the distributor changes.

Loop Distribution SubstationLoop Distribution System

In this system, the primaries of distribution transformers form a circuit starting at the substation busbars, make a loop through the area to be served, and return back to the substation. Electricity can be made to flow in either direction with the help of switches, and fault isolation is feasible.


  1. Fewer voltage fluctuations at consumers’ terminals.
  2. More reliable network, since every distributor is fed by two feeder lines instead of one, as is the case with radial distribution.


  1. More challenging design system and higher implementation cost.


Interconnected SystemInterconnected System

This system is similar to the loop distribution system, but has two or more power sources.


  1. Highest reliability.
  2. More efficient load balancing because of multiple power sources.


  1. High infrastructure costs due to the complex design and switches involved.



Distribution networks require huge initial set-up costs to have the infrastructure necessary to deliver electricity to the customer. The costs include setting up overhead and underground power lines, poles, transformer stations, and related maintenance activities on this infrastructure.


The main goal of every utility is to ensure maximum availability of electricity to all its customers and have minimum unplanned downtime. This requires maintenance activities which involve costs.

  1. Reactive Maintenance – Traditionally, utilities spend excess amounts of time scheduling emergency maintenance activities to fix defects after a fault has occurred. In most utilities around the world, this remains the most common type of maintenance. This type of maintenance usually leads to decreased equipment life and inefficient utilization of staff resources.
  2. Preventive Maintenance – This type of maintenance involves setting fixed periodic schedules to perform maintenance on equipment to prolong its runtime. This includes basic activities such as lubrication and filter changes.
  3. Predictive Maintenance – With advancements in technology, information from the distribution networks can be captured to provide increased visibility and predict failure of equipment. This can be done by capturing measurements from equipment over a period of time and triggering an alarm if they fall over or below a threshold. Maintenance is then scheduled for the equipment to fix it before an actual failure occurs.


With renewable energy becoming more affordable, energy consumers are also serving as energy generators. The traditional design of having energy generation at the top of the power systems and load at the bottom is now challenged by having a two-way flow of electricity at the consumer end. It is the task of the distribution companies to adapt to this new design change and include a model that promotes more efficient and clean use of electricity while at the same time satisfying its customers.

Cost RecoveryMonthly Bill Statement

Operation and planning activities need to be recovered from the customer. This cost is usually reflected on the customer’s utility bill as Distribution Charge or Delivery Charge.

Since the distribution infrastructure is usually built and operated by a monopolistic entity, the rate determined for recovery is set by a regulating authority to ensure it is fair to the customers.


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Regardless of the generation source, generated energy must be transmitted from the generation site to the consumer.  During the latter part of the 19th century, this mainly consisted of distributed generation, where the power was generated at or near the location it was consumed. However, around the turn-of-the-century, George Westinghouse introduced the world to the first transmission system, which leveraged alternating current as opposed to the direct current systems primarily used previously. The benefits of this high voltage transmission system quickly became evident as these new systems provided the ability to transmit and distribute electricity over very long distances. The dream of providing electricity to every home in America was becoming a reality, and the electric market was changed forever. Over the last century, electric transmission has grown to a type of superhighway for electricity, with the capacity of sending hundreds of kilovolts across entire continents.

High Tension WiresAt the start of the 21st century, the electric transmission system in the United States had truly become an interconnected network with more than 150,000 miles of high-voltage transmission lines. These lines differ significantly from the distribution lines you commonly see outside your home or office. Their sole purpose is to transmit electricity from the generation site to the distribution site. While higher voltage is the primary difference, transmission systems also include step-up and step-down transformers to smoothly connect the generation source to the distribution substation. Outside of a generation site, a switchyard is where station transformers increase voltage to the level required by the transmission system. Also at this switchyard,  breakers, busbars, and other protective equipment are used to safely and efficiently manage the flow of power away from the generation site while protecting the integrity of the transmission grid. At the tail end of the transmission system is the substation, which is most commonly associated with the distribution system. Like the switchyard, substations also include breakers, switches, and transformers. However, at the substation, transformers are used to decrease voltage to levels acceptable by the distribution system. It is common for utilities to have monitors and metering devices at a substation to ensure reliability and safety by using real-time data to better manage power levels flowing into and out of the substation.

In between the generation unit and the distribution substation are miles of high-voltage transmission lines. Transmission lines are generally twice as tall as distribution lines, ranging anywhere from 60 to 140 feet tall. These lines have multiple forms, as you can see from the figure below. While they are primarily made of metal, some can also be constructed of wood. However, wood is more commonly used for distribution poles. For above-ground transmission systems, these lines must have ample space around them free from trees, buildings, or other tall structures hazardous to the integrity of the lines.

Transmission wire diagramVoltage flowing through transmission lines can range anywhere from 40 to 765 kilovolts. This differs greatly in comparison to distribution voltages which range from about 7 to 35 kilovolts. This is due to the unique purposes transmission and distribution systems serve. Distribution systems are used to deliver energy from a local substation to the consumer. Transmission systems are used to transmit generated energy over long distances to the distribution substation.

Due to the long distances transmission lines cover and the higher voltage levels they must sustain, system operators face unique challenges operating a transmission system at an optimal capacity. To best optimize the flow of power, transmission lines use copper or aluminum because these metals have low resistance. To prevent drops in voltage over long distances, series capacitors are used to periodically balance voltage, but unfortunately at the cost of lost energy. This is why transmission systems must enforce physical constraints despite attempts to connect supply with the ever-growing demand of today’s electric grid. For example, a line is overheating. Resistance within a transmission line can cause overheating when high-frequency currents flow through a transmission system. External factors, such as temperature and wind speed can increase the chances of overheating. This can be detrimental, because it damages lines and causes line sagging. The latter can in return cause inefficiency and potential short circuits if transmission lines come in contact with external resistors, such as trees or buildings. Also, when overheating occurs, electrical energy is lost as it is changed into heat energy. This is commonly referred to as line loss and is one of the leading causes of transmission system inefficiency.

Similarly, system operators set limits on voltage levels for transmission lines in hopes of limiting transformer overloads, short circuits, and radio interference. While the purpose of transmission systems is to indeed transmit electricity at high voltage levels, these sorts of limits are critical for maintaining a reliable grid that is both safe and environmentally friendly. Reliability is a priority for all utilities, and excess voltage can in fact impede that when voltage levels exceed the capacity of the transmission system. To limit these sorts of risks that lead to damaged assets and interrupting overloads, operators try to closely monitor the flow of power through transmission lines. This reveals a growing need for transmission smart grid technologies to ensure transmission systems expand in productivity and not just size and cost.

Key similarities exist among all utility transmission systems, including the need for vast amounts of land, large high-cost assets, complex operational procedures, and an emphasis on safety. When a utility or transmission company decides to expand its transmission network, they must first plan for additional infrastructure. This includes cost analysis, efficiency analysis, and determining possible routes for transmission lines. The next step is to get permission from federal, state, and local governments and agencies including ISOs, RTOs, and FERC. The final step is to actually finance the project. This process requires a large amount of resources, especially time and money. Due to the complexities in geographical conditions, careful planning is required to ensure new transmission lines are as efficient as possible in their use of materials and their ability to provide energy. What is required to transmit electricity through Oregon’s terrain is not the same as in Texas.

This process is further complicated by the required approval from many different governmental agencies, especially due to the multiple jurisdictions interstate lines can cross. Additionally, the price for establishing transmission lines and keeping them operational is very high. The table below shows the typical capital costs for electric transmission.

Typical Costs for Electric Transmission lines by voltageToday, the electric transmission system is the backbone of the electric market. The hundreds of miles of transmission lines interconnecting generation systems to distribution systems all across the globe is what gives the sense of a widespread electric “grid.” However, this sort of interconnectivity does have setbacks. Aging infrastructure and spikes in population growth are constant struggles utilities face every day. While fighting to keep up with demand, electric transmission systems struggle with electrical resistance, line sag, transformer and capacity limits, and line loss. The United States as a whole loses nearly ten percent of all the power it generates to these technical limitations. These same technical limitations are even hindering the large scale use of renewable energy sources like wind and solar. While advances in generation technologies grow, the current AC transmission system is failing to keep up with transferring that energy to the necessary service territories hundreds to thousands of miles away.

For the electric market, encouraging electricity consumers to load shift their demand from on-peak to off-peak hours can help improve transmission efficiency. However, successful load shifting alone is not enough to help ease the tension of such a vast, interconnected system. The introduction of computerized flexible AC transmission systems or FACTS has helped by providing effective ways of controlling power flow to allow for better utilization of power lines. This increased control can also reduce harmful high-voltage transmission side effects such as overheating and line loss. By transitioning from an estimation-based model of predicting capacity based off weather, historical trends, and other system flow factors to taking advantage of smart energy management systems (EMS), transmission operators can use real-time monitoring and visualization to prevent underutilized lines and potential overloads. Some of the resulting benefits of the electric transmission system are diversified generation and an interconnectivity of the grid across multiple service territories. With higher control of power flow through the strategic, coordinated actions of FACTS devices, utilities can limit outages, by redirecting power away from overloaded lines and areas. Similarly, these systems can redirect lines to reserve power sources when blackouts occur.

Transmission lines drawingFurther development of these types of systems along with an emphasis on replacing current transmission lines with newer, more efficient systems will help the grid as a whole utilize current generation methods more efficiently and also open the door for newer ones. However, better control of the system does not necessarily prevent the grid from all possible threats, such as storms or other natural events. That is why powerline technicians, also known as linemen, are a pivotal part in the operation of an electric transmission system. Linemen are responsible for constructing and maintaining electric power transmission systems by installing or fixing capacitors, insulators, line transformers, and fuses. The job of a lineman is one of the most dangerous jobs in the world, thus an emphasis on personal and operational safety are pivotal for successful daily operation of a transmission system. Linemen are entrusted with physically maintaining and expanding the grid, thus they are highly skilled and trained individuals.

Energy transmission is one of the most pivotal and yet overlooked components of the 21st century grid. Hundreds of kilovolts of electricity are transmitted cross-country every day in the United States alone. Utilities, transmission companies, and regulatory agencies attempt to support an efficient system capable of supplying reliable amounts of energy throughout the country through constant monitoring and auditing of their operational procedures. Continued innovation in design and materials are necessary for a complete, efficient system capable of keeping up with today’s “energy-literate” consumers. With companies like Tesla paving the way with new technologies in energy storage, it begs the question of what can we do to ensure our renewable energy sources are successfully transmitting clean energy to the new energy uses of tomorrow?


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The generation of electricity comes in many forms and from many participants in the electricity market. In the past, electricity was generated almost exclusively via the burning of coal and other fossil fuels. This process is still the most widely used, but has certainly evolved. Today, many other forms of generation exist that are renewable and/or more eco-friendly, such as hydropower, solar, wind, and nuclear. Practices and programs are being instituted that help relocate the points of electricity generation to be closer to their destinations, as well as adjust times of usage to alleviate demand spikes.

World Electricity Generation 2012

Coal has always been an important commodity in the United States due to its abundance. Over a quarter of the world’s known coal reserves are located in the U.S., which equates to about 270 billion tons. Coal has been consistently used as the primary source of electricity generation due to its excellent energy content-to-price ratio. When compared to other fossil fuels, one million BTUs of energy can be produced by coal for $1.60. Comparatively, natural gas would cost $7.30 and petroleum would cost $16.20. However, the use of coal for electricity has significant drawbacks. Coal produces the most CO2 emissions of any fossil fuel. On its own, it is responsible for one third of U.S. carbon dioxide emissions. Additionally, the process of mining coal has a significant impact on the landscape and cause sulfates, nitrates, and heavy metals to run off into nearby lakes and streams. These drawbacks are the causes of a major push to decommission and shut down coal burning plants across the United States, in favor of cleaner-burning substitutes.

The burning of natural gas emits almost half as much CO2 as coal. The table below demonstrates why natural gas is becoming more popular due to its lower impact on air quality.

Carbon Dioxide 117,000 164,000 208,000
Carbon Monoxide 40 33 208
Nitrogen Oxides 92 448 457
Sulfur Dioxide 1 1,122 2,591
Particulates 7 84 2,744
Mercury 0.0000 0.0007 0.016
Table 1. Pounds of Air Pollutants per Billion BTUs of Energy. This table portrays the comparison between fossil fuels and the pollutants they emit into the air when burned. Source: EIA – Natural Gas Issues and Trends 1998.

The rising popularity of natural gas is good news for the U.S., because it’s natural gas reserves are the fifth largest in the world. This has led to natural gas providing 24% of the energy in the U.S., with only 3% of it being imported. Still, the lower price of coal compared to natural gas makes the use of coal more prevalent. Price is not the only factor, however; natural gas is much more volatile than coal so transportation can be difficult and dangerous. The extraction process (called hydraulic fracturing, or “fracking”) is also extremely invasive, labor intensive, and expensive. It requires heavy use of natural resources. A single well can consume 2 to 7 million gallons of water, depending on the region. Up to twenty wells make up a “pad” and dozens of pads can be located at a drilling site. This can result in hundreds of millions of gallons of water being used in the fracking process. A benefit of natural gas extraction is that petroleum (fuel oil) reserves are found alongside the majority of natural gas deposits.

Petroleum is the most versatile of the three fossil fuels. While coal is used almost exclusively for generating electricity and natural gas is predominantly used for heating homes, fuel oil has the capability to do both and to power internal combustion engines. This versatility creates a high and increasing demand for petroleum. Even with the recent push for alternative modes of travel and more ecofriendly sources of fuel for cars, demand for oil is projected to increase by as much as 25% by 2030. In 2015, the U.S. used a daily average of 384 million gallons of gas, which nearly matched the record high of 390 million set back in 2007. Increasing global demand is putting even greater pressure on already scarce resources, making it imperative to adapt and find alternative means to meet the energy needs of the people, such as renewable sources of fuel.

The most widely-used source of renewable energy is hydropower. In this process, power is generated by running water past a turbine, causing it to rotate and produce electricity. This makes it an incredibly popular means of generation because the water cycle is endless, which theoretically enables the perpetual creation of electricity. As portrayed in the circular chart above, in 2012 hydropower accounted for 16.5% of the world’s electricity generation.  This is due in large part to the Three Gorges Dam in China, which has the capacity to generate 22,500 megawatts of electricity. Hydroelectricity is not without its drawbacks, however. While it produces no emissions of any kind, the construction of a dam can have far-reaching environmental impacts. Fish populations suffer immensely when they try to migrate back to familiar breeding areas only to be cut off by newly-built dams. Local people and animal populations are also impacted by being relocated so an area can be flooded to create a lake. These reasons, coupled with the immense cost of building hydropower facilities, has led to the exploration of other renewable energy sources.

Solar-windfarm hybrid energy farm photoThe two most well-known renewable energy generation methods are solar and wind. The technology for harnessing the Earth’s natural resources has been around for decades, but the recent surge in popularity has occurred for several reasons. First and foremost is the decrease in cost. Over the past forty years, the price for installing a photovoltaic system has decreased by 99%. What used to cost $74 per watt now costs less than $0.70. This has been such a drastic improvement that the number of solar arrays across the globe nearly doubled between 2012 and 2014.

Wind generation has seen improvements as well. In the past several years, energy capacity for wind turbines has grown by more than 20%. Advancements in technology such as this have allowed nine states in the U.S. to produce 12% of their electricity though wind alone. Iowa and South Dakota have had such great success with wind power that they were able to use it to generate approximately one quarter of their states’ electricity. Limitations on these renewable energy sources still exist, however. Both wind and solar technologies, based on current designs, have a maximum potential capacity. Neither solar panels nor wind turbines will be able to harness all of the energy with which they come in contact or be 100% efficient. Thankfully, they do not have to be perfectly efficient because sunlight and wind are perpetually available, but once their maximum efficiencies are achieved, alternative means of harnessing renewable power will have to be created. Another major issue is their inability to increase production to match increased demand. At certain points throughout the day, referred to as peak times, energy is used in larger amounts and utility companies must account for that. However, the amount of sunlight or the speed of the wind are not factors within our control. Until a sufficient method for storing renewable power or responding to increased demand using renewables is found, fossil fuels will continue to be necessary.

Demand response is an issue that is continuing to draw increased attention, and steps are being taken to help limit or minimize spikes in electricity demands. Simply put, the goal of demand response is to decrease usage during peak times. The emphasis is on large commercial or industrial facilities being rewarded for curbing their consumption when other buildings are using more. With a ruling from the Supreme Court, the Federal Energy Regulatory Commission (FERC) was able to pass Order 745 which grants commercial buildings and factories the right to be paid wholesale price for reductions in power during cost-efficient times. This order was highly controversial, as the U.S. Court of Appeals ruled that the FERC was overstepping their authority and impacting states’ rights. The reason for the Supreme Court intervention was a disagreement with the Court of Appeals. The Supreme Court stated the FERC was acting within the powers granted by the Federal Power Act. It was decided in a 6-2 vote that Order 745’s impact crossed state lines, affected electricity markets on a wholesale scale and did not intervene at a state level. For many, the decision was considered a tremendous step in the right direction, since properly managed demand response programs can alleviate the need for power plants that were built solely to handle excessive demand situations.

Power generation models illustrationsAnother alternative to traditional means of generation that helps minimize costs and environmental impacts is to distribute the points of generation down to a local scale. Distributed generation is the concept of power being generated at the same location it is consumed. This has many positive impacts such as cutting distribution costs, reducing interdependencies, simplifying transmission processes, and greatly increasing transmission efficiency due to shorter distance of travel. The benefits associated with distributed generation make personal power generators at the household-level, such as rooftop solar panels, an increasingly attractive option.

Public aversion to pollution in close proximity can be a difficulty in localizing power generation. The phrase “Not in My Back Yard” has become a popular term describing people who do not want new developments emitting smoke and other pollutants close to their homes, yet do not have objections to these new developments being located hundreds of miles away. Unfortunately, not every method of power generation would be safe to incorporate into a distributed generation plan. For example, nuclear power has the potential to be a serious safety hazard if the plants are built too close in proximity to communities.

Nuclear production energy graphWith events like Chernobyl, Three Mile Island, and more recently Fukushima, nuclear power has a negative reputation associated with it. With recent advances in technology, however, it is safer than ever and has great potential to be a leading form of power production. Currently there are over 400 nuclear reactors in use that provide 11% of the world’s electricity, almost 2,500 terawatt-hours (TWh).

The United States alone produces one third of the world’s nuclear energy and has managed to achieve a load factor efficiency of 81% as of 2012. This is a dramatic improvement over the 56% that was standard in 1980. Much of this increase in efficiency has come from refining the process of nuclear fission, the splitting of uranium isotopes to generate heat. Much like in a coal plant, the heat is then used to boil water to create steam, and the steam is then pressurized to rotate a turbine. Also like coal plants, nuclear power generation has some undesirable emissions, though not in the form of air pollution but instead in the form of hazardous nuclear waste. As the uranium atoms are split, they produce a radioactive waste that must be properly disposed of to avoid extremely harmful effects on anyone or anything exposed to it. Aside from the hazardous byproduct, nuclear fuel is inexpensive, easy to transport, and has a much smaller impact on the environment than many other methods used today.

Because of the pros and cons of each form of generation, a combination of many methods are used to power the grid. Existing infrastructure makes it costly to let go of the past, but refusing to move forward makes for a precarious future. With legislation being passed that promotes alternatives to generation, such as demand response, and more renewable practices being encouraged, new solutions to meeting energy demands are headed in a positive direction.


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Fuel Oil
Demand Response

Distributed Generation

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Supply and demand is perhaps one of the most fundamental concepts of economics. Thriving in competitive environments, it is the idea that the price of goods sold or services provided is determined by what the market will bear. When applied to the market structure, utilities do not fit into this basic model. Alternatively, utilities tend to form monopolies, which determines how they are regulated, how ownership is handled, and how their rates are set.

A monopoly is “a market structure in which there is only one producer and seller for a product.” This market tendency can be credited largely to high operations costs.  Utilities fall into this category because it is more cost efficient to have a single provider fulfill overall demand by territory. When many small entities competed in the utility space, they grew unstable and many were acquired over time by larger parent companies. Where competition does exist in the space, whether it is among energy providers or in utility billing, the infrastructure (e.g. transport and delivery facilities) is usually owned and operated by a single source. By nature, a monopoly leads to having one provider with the power to restrict output to specific territories and set price levels, regardless of what is economically justified. Hence, strong ownership and regulation are keys to success in the utility space.


Though utilities are often referred to as monopolies, ownership can take different forms depending greatly on location.

The most popular ownership structure is the investor-owned utility (IOUs). These companies are privately owned, yet still subject to state regulation. Companies that take on this form will generally be financed by a combination of shareholder equity and bondholder debt. IOUs tend to be financially large and have multi-fuel or multi-state operations. Though these companies represent only about six percent of the utility providers, they provide service to approximately sixty percent of all utility consumers in North America.

A second ownership structure is a municipal utility. Such entities are city-owned. These providers are utility-only government agencies which are controlled by a board of elected officials. The goal of a municipal utility is to improve reliability and keep money in the community.

Another ownership structure is a cooperative. Often cooperatives service more rural areas and are private, non-profit entities.  Each customer is a member and owner of the cooperative with a vote equal to every other member. The idea of this structure is to bring the best service at the lowest cost. However, the high cost of maintaining the infrastructure needed to cover the rural areas causes prices to be high. This structure can be very cost effective though when a previously rural area becomes urban because of city growth.


Because utilities tend to operate as monopolies, governmental regulation plays an important role in the energy space with a goal of protecting the public interest. Regulatory bodies are responsible for providing operational oversight in the utility space, and play roles in the federal, state, and local government levels. The Federal Energy Regulatory Commission (FERC) governs Independent System Operators (ISOs) and Regional Transmission Organizations (RTOs). Entities such as these are ideally in place to ensure that utilities meet rules and regulations set for the good of the people.

Regulations on utilities cover a broad range of topics such as revenue and rates, resource acquisition, service standards, service quality, and the environment. Oversight of the generation of power (a producer of pollution), transmission infrastructure that has visual and physical impacts on land use, and noise levels are examples of topics covered under the environmental regulations imposed on utilities. Regulators design the pricing structures for collecting revenue and set the service quality standards and the consumer protection requirements. Regulators also oversee the financials of a utility such as reviewing and approving the utility capital investments and long-term plans, as well as have final ruling in disputes between consumers and the utilities.


As previously stated, utility rates are set by the regulators. The primary function is to address the cost of operation for utilities.

This will generally start with understanding the base cost of utility service. Here, items such as pipe and wire maintenance and the cost of owning and operating power plants are considered. Regulators would also address any fuel cost, purchased power supply, etc. depending on how the utility supplies energy to its customers. State and federal standards for environmental upgrades as well as any day-to-day operations cost are also factors. Examples of the day-to-day operations are any maintenance or repairs, service calls, meter reading, and billing.

In setting a rate, the regulator is attempting to factor in all needs of the utility as costs of operation. When the cost of doing business changes, rates will be changed to recover the costs.

In 2014, according to the U. S. Energy Information Agency (USEIA), the average price by type of consumer were:

  • Residential: 12.50 cents per kWh
  • Commercial: 10.75 cents per kWh
  • Industrial: 7.01 cents per kWh

1.4.4 CONSUMERS IN THE UTILITY INDUSTRYNumber of Ultimate Customers

Electricity prices vary by the type of customer being served. Utility customers can be broken into three categories: residential, commercial, and industrial. In general, residential and commercial consumers will have higher rates because it costs more to distribute to them. Industrial consumers use more energy, yet can receive it at a higher voltage. Therefore, the transmission process is more efficient for industrial consumers making it cheaper to supply electricity to them.

The chart above provides the number of consumers by type over the course of ten years in the United States. Despite a significant differential, each is a part of the utility space in a unique way. RESIDENTIAL

Residential consumers are the most common type of consumer and are the most studied for patterns. Residential energy consumption historically has been used mostly for space heating and cooling. In recent years, the chart below shows slight shifts in usage trends, which can be attributed to increased use of energy Enegry consumption in homes by end usersefficient homes (better insulation, efficient windows, energy efficient appliances, etc.)

Another factor that makes residential consumers unique is that they can quickly be motivated to alter their usage practices after they receive their bill. They do not mind making small changes in an effort to save money on their electric bill. COMMERCIAL

The commercial sector is slightly more complicated than residential because of the unique mix of small business owners with mid to large size businesses. Small business owners have the ability to be responsive to their bill. Their environment tends to be more flexible and open to shifts in habits to reduce costs.

Mid to large size businesses on the other hand have been historically less likely to allow their bill to influence their usage habits because individuals have not perceived control. Employees tend to experience a diffusion of responsibility to the point they believe changing their behavior will have little to no effect on cost. People also suffer from the notion that energy conservation equals reduced comfort, a serious obstacle. Overall, because so few are exposed to the cost of energy in a larger work environment, very few take strides to conserve energy. INDUSTRIAL

Industrial consumers are the utility spaces’ largest consumer, and they use energy in multiple ways. They have process heating where they raise the temperature of components during the manufacturing process such as refining crude oil. They will heat a boiler to generate steam or hot water. Electricity powers their operations. The chemical, petroleum, aluminum, glass, and steel industries are just a few examples of industries which draw a large amount of energy.


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