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7.3 AMI COMMUNICATIONS METHODS

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.

PROS

• 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.

CONS

• 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.

PROS

• 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.

CONS

• 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.

PROS

• 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.

CONS

• 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.

 

7.3.4 CELLULAR WIRELESS

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.

PROS

• 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.

CONS

• 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.

 

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:

en.wikipedia.org/wiki/Smart_meter
www.slideshare.net/SandeepSharma65/smart-meter-3
www.smartgrid.gov/recovery_act/deployment_status/sdgp_ami_systems.html
www.elp.com/articles/powergrid_international/print/volume-13/issue-10/features/amr-vs-ami.html
www.greenworldinvestor.com
w3.siemens.com/smartgrid/global/head-end-system.aspx
en.wikipedia.org/wiki/Meter_data_management
w3.usa.siemens.com/smartgrid/us/en/smart-metering/consulting-and-design/communications-assessment-tool/pages/communications-assessment-tool.aspx
www.elprocus.com/types-of-wireless-communication-applications/
en.wikipedia.org/wiki/Power-line_communication
en.wikipedia.org/wiki/Mesh_networking
https://www.landisgyr.com/webfoo/wp-content/uploads/2013/12/LAN-1306_WhitePaper_131210.pdf
https://solutions.borderstates.com/making-the-case-for-ami-part-5-understand-your-network-options/

 

This post is part of our Industry 101 Series, an ongoing campaign to provide a foundation of knowledge about our unique industry. To learn more about this campaign, please click here.

 

4.2 REGULATORY AUTHORITIES

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 interstate 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 governments 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.

4.2.3 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.

4.2.4 STATE REGULATION

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:

www.bateswhite.com/media/publication/37_media.207.pdf
www.ferc.gov/
en.wikipedia.org/wiki/Federal_Energy_Regulatory_Commission

 

This post is part of our Industry 101 Series, an ongoing campaign to provide a foundation of knowledge about our unique industry. To learn more about this campaign, please click here.

 

3.1 RETAIL MARKET

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.

3.1.1 INDUSTRIAL AND COMMERCIAL PRICING IN DEREGULATED MARKETS

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.

Like 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 may 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.

3.1.2 RATE CASE PROCESS AND PUC’S ROLE

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.

3.1.3 DEMAND RESPONSE PROGRAM

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.

 

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:

trilliantinc.com/solutions/consumer/direct-load-control
www.pluginillinois.org/realtime.aspx
energy.gov/oe/technology-development/smart-grid/demand-response
www.epsa.org/industry/primer/?fa=sold
puc.nv.gov/About/Docs/Tariffs/
www.puco.ohio.gov/puco/index.cfm/be-informed/consumer-topics/rate-case-process/#sthash.CM8NxtUl.dpbs

This post is part of our Industry 101 Series, an ongoing campaign to provide a foundation of knowledge about our unique industry. To learn more about this campaign, please click here.

 

5.4 SETTLEMENT FEES

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.

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.

 

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

citeseerx.ist.psu.edu/viewdoc/download?doi=10.1.1.510.2465&rep=rep1&type=pdf

This post is part of our Industry 101 Series, an ongoing campaign to provide a foundation of knowledge about our unique industry. To learn more about this campaign, please click here.

 

4.4 PRICING REGULATION

4.4.1 INCENTIVE REGULATION

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

In 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:

Pt = 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.

4.4.2 MARKET-BASED RATES

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.

 

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:

http://www.greentechmedia.com/articles/read/how-utility-regulation-can-deliver-value-for-customers-and-society
http://economics.mit.edu/files/1181
http://www.nber.org/chapters/c12566
http://www.krannert.purdue.edu/faculty/smartin/ios/ATM.pdf
http://www.utilitydive.com/news/ferc-revokes-market-based-rate-authority-for-berkshire-hathaway-companies/420835/
http://www.bateswhite.com/media/publication/37_media.207.pdf