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Of the physical components comprising smart grid architecture, the communications technology, a collection of communication network components that enable the flow of information throughout the grid, is the most complex.

Advanced metering with two-way communications has the potential to make meters a core element of an integrated system and better manage utility services. But what kind of communications are appropriate?

Advanced metering infrastructure (AMI) systems employ a wide array of communications technologies, including radio frequency (RF) mesh, power line carrier (PLC), RF point-to-point, and cellular. Since utilities must manage multiple communications networks, they often look for solutions that support a variety of applications and fully integrate into future operational plans.

Throughout the world, technology adoption varies by region. In Europe and North America, RF mesh and PLC are deployed most often, with Europe having a greater tendency toward PLC technology than the U.S. This is largely due to the fact that grids in Europe connect many more homes per transformer than in the U.S. Data sent from the meter over the power line may not have to pass through a transformer to reach a collector, so some PLC technologies used in Europe operate in wider bandwidths. Technology choices are oftentimes driven by local regulations. Many countries restrict use of RF mesh technologies, as unlicensed frequencies have raised concerns about interference.


7.3.1 PLC

Power-line communication (PLC) is a communication method using electrical wiring to simultaneously carry data and alternating current (AC) electric power transmission or electric power distribution.

This method is useful for utilities who want to make a more gradual migration to smart grid technology, because they can leverage existing power lines as the communications network. However, it should be noted that power lines are not well suited for fast, near real-time data communications.

Troubleshooting signal issues can be difficult when poor connections, feeder switching, worn or faulty line hardware, and other power line issues cause signal interference. It can also be difficult to push meter data in any volume from the field into the SCADA system or other applications in near real-time.

While these types of networks were once the only option for rural locations, new technologies have increased radio coverage capabilities in most geographical areas.


  • It’s cost effective. Power-line communication can transmit over long distances. In North America, this can be a cost-effective advantage for utilities serving rural communities. Because it is a hard-wired system, topographical and other physical obstacles do not affect performance.
  • It leverages existing investments. Because PLC utilizes existing infrastructure, the utility owns the communications system and there may not be as much of a learning curve involved with implementing this type of communication method.
  • It returns data useful in analyzing grid performance. This system uses the distribution network to send signals from the meter to the substation. Signal strength provides the utility with analytics that can help isolate and troubleshoot problems with insulators, transformers, and other grid devices.


  • Potential for network interference. Utilities with large industrial customers that may introduce noise and harmonics on the power line have found that this noise on the system may affect performance and distort communications.
  • Less bandwidth. Narrower available bandwidth can impact data capacity and the speed or rate at which data can be accessed in some applications.

7.3.2 POINT-TO-MULTIPOINT (Wireless)

Given the challenges with power line networks, point-to-multipoint networks began to gain popularity. These networks depend on high power transmitters to talk directly to each endpoint (or repeater) on the network.

While point-to-multipoint networks are an improvement over power line networks, they still depend on a limited number of radio paths between the endpoints and a radio base station. This makes these networks more susceptible to signal fading or shadowing caused by hills, valleys, and radio-reflective or radio-absorbing obstructions. Sometimes, the only remedy is an additional high-power base station or repeater, which can be relatively expensive.

Some providers of point-to-multipoint solutions require FCC licensing for their high-power networks. While sometimes sold as an advantage due to the designated spectrum on which they operate, FCC licensed spectrum has been subject to reallocation as recently as a last year when the VHF paging spectrum was “narrow banded.” As a result, any devices not capable of accommodating a new, narrower channel were left abandoned in the field or now require a mass hardware or firmware upgrade, or possibly both.

Operating under an FCC license does give the user a certain degree of legal recourse if someone or something accidentally or purposely encroaches on the dedicated frequency. But this in no way guarantees a “clean” channel.

Tracking down and finding sources of interference can be a difficult endeavor, and even then, this requires FCC action to enforce spectrum protections once any violators are identified.


  • It requires less infrastructure. One tower may be used to cover a large geographic territory.
  • It doesn’t raise interference issues. Since it is a licensed network, no concerns exist about other devices interfering with network communications.
  • It’s easy to deploy. Since the network may be deployed from a few towers, even a single tower, less infrastructure may be required.


  • Challenges of securing tower space: It may require installation or leasing of a tower. It may result in transmission congestion. The more meters and devices communicating to a single point, the more likely network congestion and bandwidth limitations are.
  • It’s not self-healing or self-routing. Unlike an RF mesh system, which offers many communications pathways, a point-to-point system has no built-in redundancy. So if the base station goes down, communication to thousands of meters may be lost. This can compromise grid performance and reliability.
  • It requires licensing. Along with a fee, a limited bandwidth is associated with each license. In addition, a second license may be required for distribution automation functions or other advanced grid management applications. The internal labor required to manage and maintain these licenses is also a consideration.

7.3.3 RF MESH (Wireless)

Many of today´s U.S. AMI deployments are built on an RF mesh framework. With wireless mesh networking technology, meters and other devices route data via nearby devices creating a mesh of network coverage.

Mesh networks enable end devices to communicate to the collector through multiple hops if necessary. This characteristic of mesh networks enhances network performance in three ways. First, it provides a cost-efficient way to deploy and build a network that encompasses greater distances while requiring less transmission power per device. Second, it improves system reliability since each end device can register with the collector via another communication path if the present communication path becomes inoperable. Third, by allowing end devices to act as repeaters, it is possible to deploy more nodes around a collector, thereby reducing the number of back haul paths –  a major cost factor.

Wireless mesh networks were originally developed for military applications. Over the past decade, the size, cost, and power requirements of radios has declined, enabling multiple radios to be contained within a single mesh node, thus allowing for greater modularity; each can handle multiple frequency bands and support a variety of functions as needed—such as client access, backhaul service, and scanning.

Some later wireless mesh networks use nodes with more complex radio hardware that can receive packets from an upstream node and transmit packets to a downstream node simultaneously (on a different frequency or a different CDMA channel), which is a prerequisite for a switched mesh configuration.


  • RF mesh technology can be regionally distributed, so the operator can target specific areas without needing to deploy the entire service territory.
  • It’s self-healing. If one module loses communication with the network, the network automatically finds another path to bring communications back to the head-end system. So, the network operator never needs to worry about the entire network being down.
  • It’s self-forming. The network’s intelligence enables the signal to find the optimal route back to the head-end system. This is particularly important in areas with many obstructions, such as mountains or high-rise buildings.


  • RF mesh technology may require more infrastructure than other options, especially in rural areas where meters are more spread out across the service territory.
  • It may raise interference concerns. Unlicensed frequencies used in RF mesh may raise some concerns about interference. Some countries restrict use of frequencies in the unlicensed spectrum, including RF mesh.



Smart meter traffic is characterized by small session duration, limited mobility, and a large number of devices. Therefore, it is not handled efficiently by existing wireless broadband access networks run the traditional way.

Broadband wireless networks provide ubiquitous wide-area coverage, high availability, and strong security and are, therefore, a strong candidate for handling smart meter communications. Wireless operators naturally see an enticing business opportunity in advanced metering infrastructure (AMI), because they stand to obtain additional revenue streams from existing cellular networks. Government agencies have encouraged such network sharing to reduce AMI’s energy footprint. Broadband wireless networks were not designed, however, to efficiently meet the traffic requirements of AMI.

Existing wireless broadband networks presuppose traffic that is typically modeled as consisting of individual sessions. In those sessions, duration or time scale exhibits a heavily tailed distribution and is usually orders of magnitude larger than the packet timescale. That is, the length of sessions varies widely and a typical session requires a great many packets to communicate digitally. This allows for each session to be treated as an independent connection, subject to admission control mechanisms, with associated signaling procedures for setup of radio and network resources. The signaling associated with connection setup represents minimal overhead compared to the total data transferred over the session duration.

In contrast, most AMI traffic is expected to originate from stationary devices or devices with very limited mobility and will consist of just a few payload packets between the meter and the meter data management system. Furthermore, it is expected that in normal operations, most meter traffic will be regular as opposed to being ad-hoc. That is, meters will periodically report data on the uplink and downlink data from the management system may follow. After that, a long period of inactivity until the next time meters report data will follow.

This deterministic behavior, coupled with potentially very long sleep durations between communication attempts with the network, allows for optimizing the operation of the meter so that it is scheduled to connect (or re-connect) to the wireless broadband network only at specific time instances and only for a limited period of time. During that connected interval, the meter and management system can exchange information as needed. We refer to this kind of system as time controlled scheduling.

The advantage of supporting time controlled operation is that the meter is connected to the wireless network only for short intervals of time, as needed, allowing networks’ resources to be more efficiently managed and for a very large number of devices to be multiplexed to a common base station. To contact a meter outside of its scheduled connection window, the protocol can be enhanced so that the network alternatively sends a notification indication to one or more neighboring meters located in a connected state at that time, and the meters in turn relay the request to the meter in question over a secondary wireless channel that uses an unlicensed spectrum, like ZigBee or Wi-Fi.

Congestion control is recognized as another challenge for AMI. The very large numbers of smart meters give rise to potential “traffic burst” scenarios, which can arise when large numbers of devices are simultaneously reacting to a common event, such as a power outage. To minimize the impact on the wireless broadband interface, an application layer congestion control protocol can detect the common event and stagger — that is to say, buffer or queue — transmissions from meters.

Each meter is assigned a probability (p) to transmit an alarm upon detection of a shared event. The meter will either queue (with probability 1-p) or transmit (with probability p) this event. If the message is queued, the meter will continue to monitor the air interface for an event notification from the network. This notification can be in the form of an explicit message sent from the base station or, alternatively, the base station may update the transmission probability p to 0. Upon receipt of such notification, which is sent only if another meter was able to successfully transmit the shared event notification to the station, the meter will discard the queued message.

If no such notification message is received after a random period of time, the meter will again attempt to see if the message should stay queued or be transmitted. The process is repeated until either the message is transmitted or an event notification is received from the base station. The algorithm can be generalized to allow for different event transmission probability values for different categories of shared events, with high priority given to more critical events. The delay handling can be different for different categories of shared events. The back-off delay can be made shorter for more critical events.


  • Faster deployments. Cellular enables long-range communication and can be rolled out quickly using the existing cellular infrastructure.
  • It leverages an existing network maintained by the cellular company. In most utility service territories, cellular already reaches the majority of customers.
  • It’s optimal for targeted applications. Cellular can be deployed cost effectively to support small groups of customers, even a single customer.
  • It’s proven technology. In use for more than a decade, cellular technologies are well established and reliable and are continually improved upon — particularly as it relates to security.
  • It’s secure. Because they already provide service to billions of customers worldwide, cellular networks extend the promise of safety and performance to utilities.


  • It may require head-end system changes. In the North American market, most of the widely deployed head-end systems are optimized for either RF (mesh or point-to-point), PLC, or a combination of these. Incorporating a communications technology less-widely for AMI purposes, such as cellular, may require modifications to the head-end solution.
  • It has obsolescence issues. Cellular networks tend to roll over prior to the useful life of the metering technology, so many operators are concerned about how long a deployed technology will remain viable.
  • It’s a network availability issue. The mission-critical communications that smart grid networks require need nearly 100% network availability. When utilities share public cellular networks, they are often at the mercy of the carrier’s priorities in the event of an outage.
  • It can be unreliable. If a natural disaster impacts the cellular infrastructure, networks may become overburdened.


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Deregulation is the reduction or elimination of government power in a particular industry. The goal of deregulation is to create more competition and let the free market prevail. In the energy industry, a deregulated market is one where utility companies must divest all ownership in generation and transmission of energy. The utility companies are only responsible for distribution, operation, maintenance of the interconnection between the grid and the meter, and billing of the customer.
In a regulated market, customers can only purchase utilities from their local supplier. The price is government-regulated and since only a single distribution source exists, this is what all customers pay. This creates a monopolistic marketplace. Regulation of the UK Electricity Industry diagramDeregulation was introduced in the 1980s. This allowed customers to choose from which energy supplier they wanted to purchase energy. The competition between companies eventually led to competitive prices in the energy market that are visible today in deregulated markets.



The United Kingdom’s (UK) energy market is deregulated. This process of deregulation, or privatization, began in 1989 with the Electricity Act of 1989. This act provided the foundation for privatizing the electricity supply industry in the UK.

Prior to the decision to deregulate, the UK had three state-owned electricity transportation grids that covered the following regions: England and Wales (responsible for 90% of demand), Scotland, and Northern Ireland. England had one main generation and transmission company and nine regional distribution companies, which provided the power to the majority of the UK (England and Wales). The Central Electricity Generation Board (CEGB) owned all of the transmission rights and controlled the production and distribution of electricity in England and Wales. The remainder of the market was split between the South of Scotland Electricity Board (SSEB) and the North of Scotland Hydro-Electricity Board (NSHEB).

After the UK chose to deregulate its energy market, the CEGB was divided into four different companies. Three of these companies were generating companies: PowerGen, National Power, and Nuclear Electric. PowerGen and National Power were privatized, while Nuclear Electric remained under public ownership. The fourth company that was created from dissolving CEGB was National Grid Company (NGC). National Grid Company was privatized as well and is responsible for all transmission activities.

The nine regional distribution companies were privatized with the legislation that dissolved the CEGB and these companies covered twelve distribution regions. During privatization, the regional distribution companies had to make an accounting separation between their distribution and retail activities. This was because the distribution rights gave these companies a regional monopoly and the profits needed to be monitored to ensure fairness for the customers. Initially in the 1989 legislation, the twelve regional distribution companies were given joint ownership of the NGC, but the 1995 legislation required the companies to sell this ownership.

The Scottish portion of the market was divided into three companies following the 1990 legislation. SSEB was divided into two companies. The nonnuclear assets were privatized as Scottish Power whereas the nuclear assets were renamed Scottish Nuclear and remained public. The NSHEB was privatized and renamed to Scottish Hydro.

The Electricity Act of 1989 also established a regulatory agency named the Office of Gas and Electricity Markets (OFGEM). The OFGEM is a government department, and they are governed by the Gas and Electricity Markets Authority (GEMA), which is a board of appointed members that monitor the running of the OFGEM. The primary duty of the OFGEM is to protect the interests of existing and future electricity and gas consumers by promoting competition between the various private energy companies.

Following the deregulation of the energy market in the UK, the OFGEM established price controls to help new competitors break into the market. In 2000, the Competition Act was implemented. With this act, the price controls were removed and competition between the energy suppliers was allowed to occur without interference. The OFGEM released a review of the markets and concluded that supply competition had delivered substantial price benefits for all customers.


Electricity flow and market structure8.1.3 CURRENT STATE OF DEREGULATION IN THE UNITED KINGDOM

After deregulation in the UK, four key areas of competition for energy companies remained: electricity generation, transmission, distribution, and retail. Before deregulation took effect, three major power producers in England accounted for 75% of the UK’s total electricity generation. The highly concentrated market became more diverse throughout the deregulation process, and now over 38 major power producers operate in the UK with a growing number of small power producers. Market diversification in the electric industry has helped the UK transition from a primarily coal-powered country to a country with various means of producing energy.

The electricity that is produced by generators goes on the national transmission network. The NGC controls this transmission system and is the sole system operator. As the system operator, the NGC is responsible for regulating the supply that exists on the national transmission network. Three transmission operators fall under the system operator to develop, operate, and maintain the high voltage grid. They are the Scottish Power Transmission Limited for southern Scotland, Scottish Hydro Electric Transmission plc for northern Scotland and the Scottish islands groups, and the NGC. Since only a few of these groups exist, the OFGEM has to regulate the NGC, as it is a natural monopoly. To regulate the NGC, the OFGEM sets a maximum revenue that the NGC can recover from users of the grid.

The national transmission network is a grid of high voltage transmission lines. From these lines, the electricity is passed to distribution networks, which run at lower voltages to the industrial, commercial, and domestic users. Fourteen licensed distribution network operators (DNOs) are in Britain. These DNOs are responsible for providing electricity to regional areas, and each one is assigned a regional area to service. In addition to the DNOs are Independent Network Operators (IDNOs). The IDNOs are smaller networks that will operate in an area covered by the DNOs. Both the DNOs and IDNOs must hold a license to be able to distribute electricity. The licenses have limits on the amount of revenue the company can recover from their customers, which allows the OFGEM to regulate the DNOs and IDNOs from imposing unfair monopolist prices on the customers.

The last key area for companies to compete in is the retail market. This is the area where consumers can see the changes from deregulation. Customers are now able to shop around and compare electricity suppliers to get the best deal. The retailers buy electricity from the wholesale market or from generators. The retailers then set prices for this electricity, which is what they will charge their customers. The customers’ ability to shop around for the best price from the suppliers places pressure on prices and drives better customer service. In addition, competition for customers incentivizes the suppliers to create more innovative products and services to gain a competitive advantage. The OFGEM monitors these retailers to ensure fairness to the customers.



While deregulation has been implemented in the UK for a little over two decades now, the OFGEM is always looking for better ways to improve the energy market to ensure fairness for the customers. Despite the growing number of players in the generation, distribution, and retail markets, six big companies are still in control of the majority of these markets. In order to allow the free market to prevail, the OFGEM will need to continue to work on policies to help distribute market share.


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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.


If you enjoyed this article, click here to start from the beginning of our Industry 101 Series.

Or to continue your journey, click here to access the next installment of our Industry 101 guide.


Here is a list of relevant reading material our expert identified as sources for additional information:


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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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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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In the 1990s, many in the United States pushed for utility market reform, suggesting that moving to a deregulated market would increase market transparency, drastically reduce the likelihood of power over- or under-generation, drive down prices due to increased competition, and empower consumers to make informed decisions about their power needs.

Instead of the vertically-integrated and heavily-regulated utility market that has long been the standard in the U.S., deregulated markets require the participating utilities to divest in their generation and transmission operations, allowing them to only focus on distribution and billing. Grid operators put electric generation on the market, which is then bought by retail companies and sold to end users as electricity.

The result of this deregulation is a large number of functionally separate market players, all of whom represent portions of the energy industry that would generally be handled by a single utility in a standard regulated market. A portion of the players needed to maintain a deregulated market are described below, but more may be present in a given independent system operator setup, based on the regional and federal mandates applicable to that market.



As stated previously, an independent system operator (ISO) is a regulatory organization, created on the recommendation of FERC Order 888, intended to provide oversight to utilities and transactional transparency and non-discriminatory transmission access to customers that are served by the utilities the ISO governs. Regional Transmission Organization (RTO), introduced by FERC in Order 2000, is often used interchangeably with ISO; they generally have the same goals.

In a deregulated utility market, the ISO is the central repository for information about the current and future state of the electric grid: how much power has been and will be generated by grid operators, the current market price at which retailers may sell power to consumers, and the load that consumers are currently using or forecasted to use in the future. Essentially, the ISO is the heart of the industry, taking in information from many different sources, rerouting it to the affected participants, and ensuring that everything is working as a synchronous whole.

National Operator



Market participants (MPs) are those who actively engage in transmission, energy, and/or operating reserve markets overseen by the ISO. Market participants submit bids to purchase or supply transmission, energy, and/or operating reserve to the grid, using data gleaned from agents either working for the market participants or contracted on their behalf and in compliance with the rules and regulations set out by FERC and the specific ISO. The market participant accepts financial responsibility for the transactions they submit and legal responsibility for any data they, or an agent on their behalf, submits to the ISO. Their participation in the bidding and offering process directly includes MPs in the settlement and settlement invoicing process.

Market participants often include generators, retailers, transmission operators, and transmission customers.




An asset owner (AO) is one who is responsible for assets that directly or indirectly impact the grid’s operations, including physical assets like power lines and meters, but also virtual assets like software, services, and people.

Agent Options for Market Participants

Market participants represent the asset owner’s interests in the energy market, and settlements are generated per asset owner. The division of how a specific company wants to represent itself to or settle with the ISO will define the scope of the asset owner.


5.1.4 AGENTS

Four agency relationships are available to all participants in the MISO system: MDMA

Meter Data Management Agents (MDMAs) collect, validate, and store customer usage data as part of, or on behalf of, a market participant. This data is delivered to the ISO in a pre-defined format and is used to determine the actual volume of generation or consumption used when the ISO does settlement calculations. SCHEDULING AGENT

The market participant who schedules the applicable transactions sent to the ISO is known as a scheduling agent (SA) or scheduling coordinator (SC).

Even though the scheduling agent should ensure that the participant’s bids comply with the timeliness and integrity standards set forth by the ISO, the participant is the one with a legal, financial, and operational relationship with the ISO. If any discrepancies occur, the ISO contacts the participant directly, not any agents who acted on their behalf. SETTLEMENT AGENT

Market Settlement Agent

A market settlement agent (MSA) deals with responding to the settlement invoices that the ISO sends to a market participant. Again, they may be within the market participant’s organization or a contractor who acts on the participant’s behalf.

As with the scheduling agent, the market participant assumes legal, financial, and operational responsibility for any decisions the market settlement agent delivers to the ISO on the participant’s behalf.

Transmission Settlement Agent

In the transmission market, a transmission settlement agent (TSA) acts in the same manner as an MSA does in the energy market. BILLING AGENT

A market participant may designate a billing agent as the one who accepts invoices and makes payments on behalf of the participant; this agent may be internal or external to the participant’s organization.

Similar to previous agent roles, the market participant assumes contractual obligations to the ISO on behalf of any decisions made by the billing agent.



A Local Balancing Authority (LBA) provides timely hourly or half-hourly NAI data[1] to the ISO to support market settlements.

The most visible purpose of an ISO/RTO to consumers is its use as a central clearinghouse for grid transactions between its utilities, including transmission rights and day-ahead or spot market purchases of transmission and/or generation. These transactions are known as settlements, since the ISO is the medium through which goods, services, and payments are reconciled – similar to a financial institution. Deregulated markets can have both market settlements and transmission settlements, which are used to keep the grid’s supply and demand in sync from a consumer and operational standpoint.

[1] Net Actual Interchange (NAI) – the algebraic sum of all metered interchange over all interconnections between two physically adjacent balancing authority areas.


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The prices generated for day-ahead and real-time markets are made up of several categories and fees associated with each. The figures below represent two independent system operators (ISOs) wholesale energy costs for a full or partial year and also show the significance of each fee on the total cost.

Wholesale Energy Cost 2002

Shown at right is a breakdown of several of the main fees that most often make up energy costs.

Ancillary Services – Ancillary services are needed to support the transmission of electric power from seller to purchaser. Obligations of control areas and transmitting utilities within those control areas make them necessary in order to maintain reliable operations of the interconnected transmission system.

Some ISOs pay generators for their capacity on top of the cost of energy. These capacity charges serve as an incentive for the generator to meet energy requirements in the market at all times. These prices are then bundled into energy prices for customers. Capacity charges are usually calculated based on a customer’s peak load contribution (PLC), which is their peak monthly demand, the price that a load serving unit must pay to guarantee capacity for its customers and the installed capacity (ICAP), the peak monthly demand during a specific time. Unforced capacity (UCAP) represents the actual available ICAP at any given time.

Congestion Prices are transmission charges when the market becomes congested. Actual congestion cannot occur in an energy transmission system as pushing the system beyond its limits can result in line faults and electrical fires. The term “congestion” in this context refers to higher demand, which leads to waiting markets. This can result in higher prices.

Losses refer to the energy lost due to physical resistance in the transmission network. Marginal loss costs are determined by adding the load loss charges, net explicit loss charges, and net inadvertent loss charges, then subtracting the generation loss credits from this total.

Unaccounted for energy (UFE) represents deviations due to unforeseen errors such as measurement errors, modelling errors, energy theft, load profile errors, and distribution loss differences.

UFE is calculated from the difference between the net energy delivered and the total metered demand.

PJM Wholesale Cost Full Year 2008


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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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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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The wholesale market refers to the buying and selling of power between generators and resellers. The resellers can include some or all of the following –

  • Electricity utility companies
  • Competitive power providers
  • Electricity marketers

The price for a wholesale market can be predetermined by a buyer and a seller through a bilateral contract, or it can be set by the organized wholesale market. The clearing price is determined by an auction in which the generation resources offer a price at which they can supply electricity. If a generation resource submits a bid which is a successful bid and thus would be contributing its generation to meet the market demand, it is said to clear the market. The cheapest resource will clear the market first followed by the next cheapest resource until the demand is met. When supply matches the demand, the market is cleared.



Electricity bought by the resell entities in the wholesale market is then sold to the end consumers. With electricity reforms and the advent of competition, consumers may have the option of choosing their electricity supply company. Consumers who choose their supplier are also known by the term choice consumers. On the other hand, consumers who do not choose a supplier are served by their incumbent utility through a service called provider of last resort – POLR.

All the retail markets are regulated at the state level.


Energy Market Simplified View5.2.3 WORKING OF AN ELECTRICITY MARKET

The major players in an electricity market are:

  • Electricity generation resources
  • Electricity suppliers (retailers)
  • Electricity system operator (firms like ERCOT)
  • Domestic/commercial customers

The electricity supplier (retailer) is responsible for purchasing power from the wholesale market through either long-term contracts or several short-term agreements, selling it to the customers, and billing them for the electricity used. As discussed above, with the advent of competition, consumers can choose their supplier and suppliers can choose their generation resource.

The electricity system operator (like ERCOT) is responsible for:

  • Balancing the system in real-time, i.e. matching the demand and supply of electricity at the agreed frequency.
  • Calculating the imbalance for each supplier, i.e. the difference between the amount of electricity purchased and the total demand of the supplier’s customers, and sending out the invoices for the settlement period under consideration.


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Here is a list of relevant reading material our expert identified as sources for additional information: