Remote Central Station Generation Systems

Central Station Generation

Over the next several years we are likely to see small scale distributed generation acquire an increased share of electric generation in this country. See Post entitled Distributed Generation – and Old Idea Reconsidered.  However, notwithstanding the growth of distributed generation, we are still going to rely primarily upon the historic system of large central station generators interconnected by a complex high voltage transmission grid.

The following chart shows electricity generation by fuel source in the United States:

by-fuel-chart

As depicted above, the vast majority of our electricity comes from large coal, natural gas and nuclear plants. These are the types of central station generators promoted by George Westinghouse more than 100 years ago.

The following video explains how electricity is produced at one of those central station power plants:

No matter how much distributed generation is added, the historic reliance upon central station generators plants is not going to disappear any time soon. Instead, central station generation is likely to be made cleaner with natural gas plants replacing coal plants and utility scale renewables being added to the mix.

High Voltage Transmission

All of the central station generators interconnect to the electric transmission grid. For the most part all of that generation stands ready to provide electricity when needed. However, not all of the plants are needed all of the time.

In states that remain highly regulated utilities own their own generating plants. They dispatch those plants strategically to meet their customer load requirements at the lowest overall operating costs.

In states where Independent System Operators (ISO) manage the grid generating plants operate at the direction of the ISO usually as a result of participation in a competitive auction.

Transformers located on the site of each generator boost the voltage of the generated electricity so that it can be transmitted at high voltage levels over long distances on the grid. After transmission the voltage is reduced at local substations so that it can be transported the final distance to the points of usage.

The following video explains how the electric transmission system delivers electricity from a central station generator to a local distribution system for final delivery to customers:

Author

I. David Rosenstein worked as a consulting engineer and attorney in the electric industry for 40 years. At various times during his career he worked for utility customers, Rural Electric Cooperatives, traditional investor owned regulated utilities and deregulated power generation companies. Each of his posts in this blog describes a different aspect of the past, present or future of the electric industry. 

Electricity Sales in the Power Market

Conversion from Regulation to a Competitive Power Market

Explaining the purchase and sale of electricity used to be easy. Utilities produced electricity at their own generating plants. They transmitted that electricity over their own transmission and distribution facilities. And they sold their electricity to their customers at regulated rates. The three components of electric service – generation, transmission and distribution – were referred to as a single “integrated” or “bundled” service.

Explaining the purchase and sale of electricity is no longer that easy. The following have made it much more difficult:

  • The “unbundling” of the generation component of electric service; and
  • Changes in the relationship between utilities and their end-use customers.

The Unbundling of the Generation Component of Electric Service

In 1995 the Federal Energy Regulatory Commission issued its Open Access Orders requiring utilities:

  • To unbundle their generation service from their regulated transmission and distribution services; and
  • To provide open access transmission service to all generation owners.

Since that time many utilities have operated their generating facilities in new unregulated affiliates. Other utilities have completely exited the generation business and sold their generating plants to unregulated Independent Power Producers (IPP). As a result, many end-use customers no longer purchase generation produced by their utility as part of the utility’s integrated service.

Customers now purchase the generation component of service under one of the following alternatives:

  • In some states (mostly in the Northwest and Southeast where Independent System Operators (ISOs) have not been formed) customers still purchase generation produced by their utility as part of a single integrated service. The cost of that generation is included as part of the regulated rate for the single integrated service.
  • In states where customers have been given the option to purchase generation from a competitive non-utility retail supplier customers can purchase their generation either from such a supplier or from their utility. Both the competitive supplier and the utility will obtain their generation supply on a wholesale basis either from an IPP or from a power market.
  • In states where ISOs have been formed but customers have not been given the option to purchase from a competitive retail supplier generation will remain part of the integrated service provided by the utility. The utility may provide the generation either from its own facilities. However, it may also obtain generation from an IPP or the regional power market. The cost of generation and/or the cost of purchases will be included in the utilities’ regulated rate for the single integrated service.

Relationship Between Utilities and Their End-Use Customers

No matter where their generation service comes from end-use customers can be assured that their utility will continue to provide transmission and distribution of that generation. And those services will be regulated as they have been for over 100 years.

Diagram of sales in the competitive power market
Electric Delivery in a Deregulated State Market

Where customers have been given the option to purchase from a retail supplier they may be dealing with two entities for their electric service. The utility will send an invoice for the delivery service and the retail supplier will send an invoice for the generation service. However, in some cases the utility has been made the collection agent for the supplier and will include a supply charge line on its invoice to collect the retail supplier’s charge.

Where customers decide not to take advantage of the competitive retail supply opportunity they rely on their utility to purchase their generation component from the competitive power market. The utility will typically include a separate line on its invoice to show the cost of the generation that it purchases in the competitive power market.

The ISOs Each Manage a Power Market

As explained above, much of our generation is now bought and sold in power markets. But how does such a power market work? And how are the competitive prices determined?  

The power markets are operated by the regional ISOs. Those markets generally consist of two products – capacity and energy. The ISOs operate their markets in accordance with rules approved by the Federal Energy Regulatory Commission (FERC). The FERC expects its market rules to result in prices for capacity and energy that will result in reliable and affordable electricity for end-users in both the near term and the long term.  

Retail suppliers – that is, both competitive retail suppliers and the utilities that provide the generation component from the market as part of their bundled service – are the buyers in the ISO auctions. They buy the capacity and energy needed to meet their end-users’ needs.

Generation plant owners (including some utilities that continue to own generation facilities) are the sellers in the auctions. They own the hundreds or thousands of generation sources that are interconnected to the ISOs and submit bids in the auctions for the sale of capacity and energy. Unlike a regulated utility, generation plant owners operating in a power market are not guaranteed a return on investment.  They rely on the auction clearing prices for the possibility of a profit.

The Capacity Auction

Capacity represents the generating resources required to ensure that there will be adequate electricity available to meet end-use customer requirements. Capacity is measured in megawatts (MW). 

Retail suppliers purchase capacity to ensure that there are adequate resources interconnected to the ISO to meet their end-use customers’ share of the maximum demand on the system. Generation plant owners sell capacity in the form of a promise to generate electricity when called upon to run by the ISO.

Because capacity is a promise to generate electricity rather than the actual generation of electricity it is sometimes referred as iron in the ground. The ISO rules are intended to ensure that there is adequate iron in the ground to meet end-use customer requirements.

By definition, capacity is a product that ensures the availability of electricity in some future time period. ISOs will conduct an auction for a future period to determine the price for capacity in that period. PJM, for example, conducts its capacity auction for a period three years into the future. 

Because the supply and demand balance may vary throughout any ISO’s system there may be different settled capacity prices for different points on the system. Any plant that clears the capacity auction – in other words, whose bid (in $/MW/month) for the promise to deliver electricity has been accepted – will receive the cleared price for their capacity in the future time period whether or not they are asked to produce any energy.

Plants that have promised to generate electric will actually generate electricity only if and when, based real time demand and their operating costs, they clear the energy market and are directed to operate. However, if a plant receiving capacity payments fails to operate when called upon it will be subject to a severe penalty. See GAO’s Report to Congressional Committees on Electricity Markets for a detailed discussion and review of capacity markets.

The Energy Auction

Electrical energy is the ability to do work by the movement of charged particles through a wire. Energy is what is actually produced at a generating plant at the time it is needed by end-use customers. While capacity represents the ability to do work and is measured in MW, energy is the actual performance of that work and adds a time element to capacity. Energy is, therefore, measured in megawatt-hours (MWh). 

Retail suppliers purchase energy to meet their end-use customers’ real time energy requirements. Generation plant owners sell energy to meet the retail supplier requirements. 

The ISOs conduct auctions for each hour of the day to determine the settled price for energy (in $/MWh) at multiple locations on their systems. The settled prices in the auction will determine which plants are dispatched in each hour and what price they will be paid for their production.

Plants will, in general, only operate when the settled price exceeds their operating costs. To keep the cost of electricity as low as possible the lowest cost plants will clear first – in other words, when demand is low – and the higher cost plants will clear only in hours when demand increases. The following graph shows how different plants may be dispatched on the PJM system throughout the day as demand varies:

Graph showing plant dispatch in a competitive power market
Source: PJM.com

Plant dispatch then translates to energy prices. Thus, when usage is high, and the ISO dispatches the more expensive plants, the price of electricity to retail suppliers will be highest. The highest cost operation and the highest priced energy usually occurs during late afternoon hours in the summer months when air conditioning use peaks. The following graph shows a typical difference in electrical energy prices across the hours of a typical day in summer and non-summer months:

Graph of electrical prices arising out of the competitive power market

Author

I. David Rosenstein worked as a consulting engineer and attorney in the electric industry for 40 years. At various times during his career he worked for utility customers, Rural Electric Cooperatives, traditional investor owned regulated utilities and deregulated power generation companies. Each of his posts in this blog describes a different aspect of the past, present or future of the electric industry. 

Who Controls the Electric Transmission Grid?

Utilities Own Portions of the Electric Transmission Grid

Today’s electric transmission grid consists of 360,000 miles of high voltage transmission lines. While we often refer to a single grid, the following map shows that there are actually three transmission grids in the United States:

Source: energy.gov

Who controls these grids? And how do they ensure that the lights come on every time that we flip the switch?

A short time ago the answer would have been simple.  Your local utility owned and managed the portion of the electric transmission grid that interconnected its generating plants to its local distribution system. Your utility also owned and managed the portion of the electric transmission grid that interconnected its system with neighboring utilities (referred to as “inter-ties”). These inter-ties facilitated purchases and sales of wholesale power. Today the answer to the question of who controls the grid is not quite that simple.

The Northeast Power Blackouts

The old system of individual ownership and management of portions of the electric transmission grid had its weaknesses. Those weaknesses first became apparent in 1965 when a blackout of the Northeast United States left 30 million people without power. It turned out that the inter-ties between utilities enabled an outage on one portion of the electric transmission grid to lead to numerous successive outages on other portions.

In response to the 1965 Northeast Blackout the utility industry agreed that the utility-by-utility planning was not working. They promised to start planning their high voltage transmission systems on a regional basis. They also promised that they would voluntarily implement uniform reliability procedures.

The path to a reliable transmission grid was a little bumpy. The utilities did not all comply with the voluntary procedures and, in 1973, there was another major Northeast Power Blackout. In response to that second Blackout, in 2005, Congress passed legislation giving the Federal Energy Regulatory Commission (FERC) authority to enforce mandatory reliability standards. In 2006 FERC delegated responsibility for developing the mandatory reliable standards to the North American Electric Reliability Corporation (NERC).

The current electric transmission grid, developed as a result of the regional planning processes and compliance with mandatory reliability standards facilitates an electric grid that provides for reliable transmission of power over multiple utility systems.

The FERC’s Open Access Orders

The availability of reliable long distance transmission of electricity led policy makers to conclude that generation should be provided on a competitive, rather than regulated, basis. Therefore, in 1995 the Federal Energy Regulatory Commission (FERC) issued its Open Access Orders. Those Orders required every utility to provide non-discriminatory access to its high voltage transmission system. In effect, the FERC was turning the electric transmission grid into an interstate highway system where each utility would have to transport their own generation and the generation of others on a equal basis.

When it issued its Open Access Orders the FERC suspected that utilities could not be trusted to provide access on a non-discriminatory basis. They were concerned that utilities would favor their own generation at the expense of other parties’ generation.  The FERC was afraid that it would have to deal with a raft of complaints from generators who claimed that utilities were violating the non-discriminatory access provisions of the Open Access Orders.

Creation of the ISO/RTOs

In order to make sure that non-discriminatory access was actually achieved the FERC strongly urged utilities to turn control of their transmission facilities over to new entities called Independent System Operators (since renamed Regional Transmission Operators or ISO/RTOs). ISO/RTOs are non-profit entities whose members include utilities, generators and customers. The members elect an independent Board of Directors who manage the ISO/RTO staff.

Utilities that join an ISO/RTO retain ownership of their high voltage transmission facilities. But they operate those facilities at the direction of the ISO/RTO. The ISO/RTO is responsible for coordinating and directing the flow of electricity over its region’s high-voltage transmission system. The ISO/RTO also performs the studies, analyses, and planning to ensure regional reliability for future periods. As discussed in the Post entitled Electricity Sales in the Power Market the ISO/RTOs also manage the wholesale power markets in which competitive generation is bought and sold.

The following are the ISO/RTOs that have been created in the United States:

Map of the ISOs in North America
Source: ferc.gov

The utilities in the Southeast, the Northwest and the Southwest (other than California) have not joined ISO/RTOs and continue to both own and operate their own high voltage transmission facilities.  

The following video, prepared by the California ISO/RTO, describes the ISO/RTO responsibilities with respect to operation of their respective portion of the electric transmission grid.

The FERC treats the ISO/RTOs as the providers of all transmission service on their respective portion of the electric transmission grid. The ISO/RTOs are, therefore, responsible for ensuring that transmission is provided on a non-discriminatory basis, as required by the Open Access Orders. The ISO/RTOs also collect all charges for providing transmission service on their portion of the grid. They distribute those revenues (other than those required for internal operations) to the utility owners of the high voltage transmission facilities. That distribution ensures that each utility continues to recover their regulatorily determined revenue requirement. See Post entitled Determining Just and Reasonable Electric Rates for an explanation of regulatory ratemaking.

Multiple Entities Control the Grid

Therefore, the answer to the question of who controls the electric transmission grid has three parts:

  • First, the utilities still own the high power transmission lines that make up the electric transmission grid. They are responsible for maintaining those facilities and keeping them in good working order.
  • Second, in most parts of the country the ISO/RTOs are responsible for directing the operation of the electric transmission grid and for long term planning.
  • Third, the NERC, through FERC, is responsible for ensuring that the utilities operate and maintain their facilities in compliance with mandatory reliability standards.

Author

I. David Rosenstein worked as a consulting engineer and attorney in the electric industry for 40 years. At various times during his career he worked for utility customers, Rural Electric Cooperatives, traditional investor owned regulated utilities and deregulated power generation companies. Each of his posts in this blog describes a different aspect of the past, present or future of the electric industry.