So You Want to Build a Wind Farm Project

Surprise from a Long Lost Uncle

You recently learned that your long lost rich uncle Ned died and named you as his sole beneficiary. There are now $20 million in your bank account. You want to invest the funds wisely. And, because you consider yourself an environmentalist, you want to do something to benefit the environment.

You have started to look into investing in a renewable energy project. A small wind farm of about 20 MW seems like it might work for you. You decide to name your wind farm project “Breezy Acres, Inc.” What are you going to have to do before you can turn Breezy Acres into a profit making entity?

The Electricity Produced by 20 MW

Breezy Acres will produce enough electricity during a year to meet the electrical needs of about 4000 homes. However, because the wind does not blow all the time, the wind turbines will probably only operate at a 25% capacity factor. In other words, the turbines might be operating at rated capacity only 25% of the year. Thus, the generation from your wind farm project will, at times, be less than the requirements of the 4000 homes and will, at times, be more than the requirements of the 4000 homes. 

Converting Wind to Electricity

To produce electricity at Breezy Acres you will use 10 two MW wind turbines. Each turbine consists of two or three rotating propeller-like blades and a nacelle. The nacelle contains the components that convert the rotation of the blades into electricity

As wind blows over the turbine’s blades they will drive a low speed shaft at speeds of about 7-12 rotations per minute (rpm). However, electricity cannot be produced at those speeds. Therefore, the low speed shaft is connected to a gearbox that converts the speed of the low speed shaft speed to about 1,000 to 1,800 rpm on a high speed shaft. The high speed shaft drives a generator which converts the mechanical energy of the high speed shaft into electrical energy.

A wind vane and anemometer are mounted on top of the nacelle. The controller will use the wind direction, measured by the wind vane, to turn the turbine in the direction that will result in the highest rpm of the blades. The controller will use the wind speed, measured by the anemometer, to prevent the blades from turning at speeds of lower than about 14 miles per hour (at which electricity cannot be produced) or higher than about 60 miles per hour (at which the blades can be damaged).

Additional information regarding the operation of wind turbines can be found at energy.gov and in the following video:

Project Development

Your first job will be to determine if Breezy Acres is even feasible. Until you determine that it is feasible you do not want to spend too much of your inheritance.  Therefore, the development stage of the process consists of the following:

  • Securing a site at which the turbines will be located;
  • Obtaining all government permits required for the project;
  • Conducting financial analyses to determine financial feasibility;
  • Arranging for an interconnection to the transmission grid;
  • Arranging for the purchase of the equipment;
  • Securing financing; and
  • Deciding whether to sell the output to the market or under a purchase power agreement.

All of the above should be arranged on a contingency, or option, basis. If possible, you should not finalize anything until you know that you are going to proceed with the project.

Selecting a Site for the Wind Farm Project

The most important issue in developing a wind farm project is choosing the right location. Choosing the wrong location can result in the following:

  • There may be inadequate wind to generate the electricity needed to make the project profitable;
  • The project may be located so far from the transmission grid that the cost of the transmission line required for interconnection will make the project uneconomic; or
  • The local market prices for capacity, energy and renewable energy credits may be inadequate to turn a profit.

The Site Must Have Adequate Wind Speed

Wind speeds vary greatly throughout the United States. The following is a map of wind speeds at 50 meters height:

Wind turbines will not generate electricity unless the wind is blowing at least 14 miles per hour. And the higher your wind speed is above 14 miles per hour the more electricity you will be able to produce at your wind farm. So finding the right location is critical to your project’s profitability. As can be seen from the above maximum wind speeds are available along the coasts or in the Midwest.

You will have to hire experts to test the wind speeds at any location that you are considering. Wind blows faster at higher speeds. Therefore, wind speed tests must be conducted at the height at which the windmill will be located. Some of today’s windmills are higher than 400 feet.  

The Cost of Interconnection to the Transmission Grid

Your wind farm project will not have any value unless you can deliver your electricity to the grid. Each Independent System Operator (ISO) has a set of rules that govern interconnections of new generating facilities to the grid. All of these rules require that you, as the owner of the new generator, pay all costs incurred by the ISO and the transmission owning utilities to accommodate your facility. Those costs include the following:

  • Any engineering costs incurred to design facilities required for the interconnection;
  • The costs of the transmission line that runs from Breezy Acres to the closest utility owned transmission line;
  • The cost of interconnecting the new transmission line to the existing grid; and
  • The cost of any impact the operation of Breezy Acres may have on other remote locations of the grid.

It may take the ISO several years to determine the costs of interconnection. And those costs, which could be several million dollars, could be the difference between profitability and failure of the project. Therefore, you cannot make final plans for the project until you get that interconnection cost number from the ISO.

Revenues From the Sale of Capacity, Energy and Renewable Energy Credits

Breezy Acres will produce three products available for sale to the market – energy, capacity and renewable energy credits (RECs). The quantity produced and the price for each will make or break the profitability of the project. For more discussion on sales to the competitive power market see the Post entitled Electricity Sales in a Power Market. You can hire an expert that can project the revenue that your wind farm project is likely to recover once it is in operation.

Revenues from Sales of Capacity

Capacity is the power, in MW, that Breezy Acres will be able to deliver to the system at any time. Your turbines will be rated at 20 MW. So 20 MW could be the capacity that Breezy Acres has available for sale. But the ISO depends upon capacity to make sure that the lights stay on. And since the wind does not blow all the time no one can be assured that 20 MW from Breezy Acres will always be available to power the lights. 

You will have to run tests to determine exactly how often the 20 MW at Breezy Acres can be relied upon. These types of projects typically have a capacity factor of about 25%. Therefore, Breezy Acres may only be able to sell 25% of the 20 MW of rated capacity – or 4 MW. 

Your expert can project the price for capacity, in $/MW/month. But you will not know the exact price until the ISO conducts its capacity auction for a forward period. It is not unusual for developers, like yourself, to delay construction of your project until you are assured that the capacity prices arising out of the capacity auction will be adequate to generate a necessary profit.

Revenues from the Sale of Energy

Energy is the electricity that Breezy Acres produces while it is in operation. Your expert can project the quantity of electricity, in MWh, that Breezy Acres is likely to produce in any year. 

If you are selling into the ISO market the price for each MWh of energy will change by the hour depending upon the demand for electricity on the ISO system in that hour. The price that the ISO pays for energy in any hour is based upon the running costs of the most expensive generating unit that is generating electricity. Your expert should be able to project the energy prices, in $/MWh, for a typical year of operation.

During many hours of the year, when demand is low, the price of energy is based upon the very low running costs of a renewable plant or a nuclear plant. However, during those very hot spells of the summer, when everyone is running their air conditioning night and day, all generating plants, even the most expensive oil burning plants, are called into action.  And the running costs of those expensive plants set the energy price for all plants that are producing electricity during the hour. 

You may commiserate with your friends and neighbors who are complaining bitterly about the heat and their electric bills during those hot spells. But you will also know that the revenue that you receive for sales during those hot spells are what will make Breezy Acres profitable.

Revenues from the Sale of Renewable energy credits

Electricity produced by wind turbines is a premium product. Many states require their electric providers to include a certain amount of renewable energy in their energy portfolio. And many competitive retail electric suppliers offer their customers electricity that is primarily produced from renewables. This creates market demand and makes energy produced by renewables a little more expensive than other forms of electric energy. 

Electricity produced by renewable plants is intermingled with other electricity on the grid. So it is impossible to prove that electricity produced at a renewable plant is being delivered to a particular customer. However, each kWh produced by a renewable plant is accompanied by a Renewable Energy Credit, or REC, which can be sold independently from the kWh. Purchase of an REC is proof that the purchaser has bought renewable energy for resale. 

Breezy Acres will be producing an REC for each kWh that it generates. You will be able to sell these RECs on the open market. Your expert can project the revenues that you are likely to recover from the sale of RECs.

Securing the Site

Because each wind turbine can interrupt the flow of air to the other turbines you need plenty of space for your wind farm project. You might need as much as 500 acres. You do not need to own 500 acres of land. More likely you will want to lease 500 acres from one or more farms. The farmers will be able to use the land around your turbines as long as they do not interfere with your operation.

The cost of these leases could be between $60,000 and $80,000 each year. However, you do not want to start paying for these leases until you are sure that you are going to proceed with the project. You should be able to secure the site by entering into an “option to lease” for a small amount of money. You will convert the option to a lease when you are sure that the project is going to proceed.

Financing the Wind Farm Project

You will have to go out and obtain bids for the cost of installation of your 10 two MW wind turbines. However, typical total costs are around $40 million for this type of project. Your expert projects that net annual profits from the operation of Breezy Acres should be around $6 million. His projection is just an educated guess. But if he is right you will be making a 15% annual return on a $40 million investment. And even if he is off by a little it still looks like a great investment opportunity!

But Uncle Ned did not leave you $40 million. He left you only $20 million. You are going to have to borrow the remaining $20 million from a bank. Interest rates for a company like Breezy Acres might be around 10%. So annual interest payments for a $20 million loan will be $2 million.

You expect that it will be easy to get a loan. After all, the project is going to throw off $6 million each year, well more than the $2 million interest payment owed to the bank.

But banks do not have the same appetite for risk that you do. Your anticipated annual earnings are based upon your expert’s estimate of the market prices for capacity, energy and RECs. The bank does not want its loan repayment to be dependent upon the volatility of market prices. They tell you they will not approve a loan for your wind farm project unless you can assure them of fixed capacity, energy and REC prices.

The Purchase Power Agreement

The only way to fix the capacity, energy and REC prices is to enter into a fixed priced purchase power agreement under which you sell all of the Breezy Acres output to a purchaser at a fixed price. There are plenty of participants in the energy markets that will be happy to enter into such a purchase power agreement. They will purchase your output and sell it into the market at market prices. However, that means that they are taking on the risk of the volatility of market prices. In order to take on that risk they will want the fixed price that they pay to leave them plenty of opportunity for profit. In other words, they are going to want some portion of that anticipated $6 million in annual profit. 

Figure that the purchaser under the purchase power agreement will want to keep one third of the anticipated profit. This leaves Breezy Acres with only $4 million of profit under the fixed price purchase power agreement. Of that $4 million you will have to pay $2 million to the bank in interest payments for the $20 million loan.

That leaves you with $2 million of the total $6 million in potential profits from operations of Breezy Acres. But $2 million is still a 10% return on your $20 million investment. And, with the purchase power agreement, you no longer have to contend with the uncertainty regarding the price for sales. Therefore, it still seems like a pretty good investment of your inheritance.

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. 

The Watts, Volts, Amps and Ohms Post

The Need for This Post 

When I started writing this blog my goal was to present a useful explanation of electricity and the electric industry without using the technical terms and formulas for Watts, Volts, Amps and Ohms that have so long challenged physics students. However, I have been advised that my discussion without some explanation of these terms. So with some reluctance I write this post.

Electrical Power

Electrical power is measured in Watts (W) or megawatts (MW). Each MW is equal to 1,000,000 watts. 

Since it takes 100 watts to light a 100 watt electrical light bulb, a typical power plant, rated at 500 MW, should produce enough power to light a community consisting of 5,000,000 of these 100 watt light bulbs. 

Two things of note here. First, although a 500 MW plant might be built to serve a community consisting of 5,000,000 light bulbs the 5,000,000 light bulbs are not likely to all be in use at the same time. They might all be lit from 7 PM to 10 PM on a typical night. But during other hours of the day fewer than all 5,000,000 will be lit.

The electric utility industry has always dealt with this challenge. It must build facilities required to meet customer usage at the time of the system peak.  But during off-peak hours much of the utility plant will be out of use. Utilities always viewed this idle capacity as a wasted opportunity. They wanted to make maximum use of their plant. They hoped to sell enough electricity during off-peak hours to “level out the load curve”. With the support of their regulators they implemented “declining block rate structures” with price discounts that encouraged off-peak consumption.

 In the 21stcentury we are more concerned with conservation than with encouraging use of idle capacity. Therefore, utilities no longer implement declining block rate structures to encourage off-peak consumption. Instead, they now seek to level out the load curve by implementing programs to encourage customers to reduce on-peak usage.

The second thing to note about our example of a 500 MW power plant is that the 500 MW plant will not really light 5,000,000 light bulbs. As will be explained in more detail below, a portion of the 500 MW produced at the plant (approximately 5%) will be lost to resistance as it travels on the transmission system. Thus, the 500 MW plant will actually only light 4,750,000 100 watt light bulbs. 

Voltage and current 

Voltage (measured in volts) is the pressure that pushes electric power through the circuit. Current (measured in amperes or amps) is the speed by which the electric power moves in the circuit.

A typical generating plant produces electricity with between 2,300 volts and 22,000 volts. In order to push the electric power on long distance transmission lines transformers located at the generating plant step up the voltage to between 69,000,000 volts and 765,000,000 volts. 

After traveling on the high voltage transmission lines the electricity goes to a local substation where step down transformers convert it to voltages of 35,000 volts or less. These distribution level voltages are then reduced to 110 volts or 220 volts for household use by transformers located in the boxes that we see hanging on utility poles in our neighborhoods.

Power, voltage and current are related by the following formula:

Power (in watts) = Voltage (in volts) x current (in amps)

The takeaway here is that, when the quantity of power is fixed, current can be increased by reducing voltage and current can be decreased by increasing voltage.

Resistance 

Resistance (measured in Ohms) is the degree to which a material or device reduces electric current flowing through it. The copper wire over which electricity flows has resistance that reduces the amount of electrical power available for usage. As indicated above, the resistance in copper wire used in high voltage transmission lines reduces power flowing over it by approximately 5%. 

The resistance of any material is inherent in that material. However, the quantity of losses that result from transmission of electricity over that material can be varied. 

By combining several complicated formulas it can be seen that losses resulting from resistance on the lines are directly proportional to the current in amps squared. Therefore, line losses can be reduced by reducing the current on the line. And as indicated in the formula in the last section of this Post current can be reduced by increasing voltage. Therefore, the higher the voltage used for transmission, the lower the line losses and the more efficient the electricity delivery. Engineers try to use high voltage lines where possible to reduce the losses of electric power delivered on the system.

This issue of line losses associated with transmission leads to one of the benefits of the use of distributed generation. Because distributed generation is located close to the point of use the electricity that it produces is not subject to the line losses that occur in long distance transmission.

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. 

Protecting the Grid Again Cyber Attack

 

Congress Passed EPACT 2005 in Response to the 2003 Northeast Blackout

A failure of voluntary compliance with industry reliability standards led to the 2003 Northeast Power Blackout. To prevent future such blackouts Congress passed the Energy Policy Act of 2005 (EPACT 2005). EPACT 2005 gave the Federal Energy Regulatory Commission (FERC) authority to implement mandatory reliability standards and to assess penalties for non-compliance.

FERC Names NERC the Electric Reliability Organization

EPACT 2005 directed FERC to identify an independent entity, referred to as an Electric Reliability Organization, that would be responsible for developing and enforcing mandatory standards for the reliable operation and planning of the bulk-power system throughout North America.

In June, 2006 FERC named the North American Electric Reliability Corporation (NERC) as the Electric Reliability Organization (ERO). NERC now operates under the direction of FERC.

NERC’s Role as the Electric Reliability Organization

NERC operates as a 501(c)(6) not-for-profit corporation. It is run by a Board of Trustees elected by its 1900 members, all of whom are participants in the electric industry. NERC states that its role is:

to improve the reliability and security of the bulk power system in the United States, Canada and part of Mexico. The organization aims to do that not only by enforcing compliance with mandatory reliability standards, but also by acting as a catalyst for positive change — including shedding light on system weaknesses, helping industry participants operate and plan to the highest possible level, and communicating lessons learned throughout the industry.

The following video explains NERC’s history and responsilities:

In its role as ERO NERC develops the mandatory reliability standards that owners and operators of the high voltage electric transmission lines and interconnected generation facilities must now follow.  The transmission system and the generating facilities are referred to collectively as the Bulk Electric System or BES. NERC develops its mandatory standards through standing committees whose members include members of the industry. 

NERC manages eight Regional Entities (depicted in the following map) that are responsible for auditing industry compliance with the mandatory standards.

NERC’s Role in Grid Cybersecurity

NERC’s first action after being designated ERO was development of reliability standards related to the operation of BES property. Those early reliability standards related to things like tree trimming, testing of relays and breakers, physical barriers to trespassing and testing of backup systems.

NERC then moved on to mandatory reliability standards related to grid cybersecurity. NERC implemented 9 critical infrastructure protection (CIP) standards that are intended to provide for grid cybersecurity.

These 9 CIP cybersecurity standards require all owners and operators of facilities interconnected to the BES (refered to as Responsible Entities) to identify and protect their Critical Cyber Assets. NERC defines Cyber Assets generally as programmable electronic devices , including the hardware, software, and data in those devices. NERC defines Critical Cyber Assets as Cyber Assets that are essential to the reliable opeation of Critical Assets, which are defined as facilities, systems and equipment which, if made inoperable, would affect the reliable operation of the BES.

In other words, the 9 CIP cybersecurity standards require Responsible Entities (the utilities and generation owners) to identify and protect from attack all cyber equipment which, if lost, could affect the reliable operation of the Bulk Electric System. In particular, the 9 CIP cybersecurity standards require the following: 

  • Utility identification of their own Critical Cyber Assets
  • Installation of controls for Critical Cyber Assets
  • Security training for employees that operate Critical Cyber Assets
  • Establishment of electronic security perimeters around Critical Cyber Assets
  • Establishment of physical security around Critical Cyber Assets
  • Systems security management
  • Cyber security incident planning and response planning
  • Recovery plans for incidents related to Critical Cyber Assets

If one of the Regional Entities finds that a Responsible Entity has not complied with one or more of the CIP standards they will work with the Responsible Entity to correct or “mitigate” the violation. The Regional Entity may also bring the violation to the attention of the FERC which has authority to assess penalties of up to $1million per day per violation. While most of the FERC penalties have been far less than this amount, in February, 2019, FERC announced penalties totaling $10 million against Duke Energy for over 100 violations going back over three years.

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. 

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. 

Nuclear Power Industry Headed in Two Directions

Nuclear Power Industry in the News

On May 8, 2019 the National Public Radio web site posted two articles related to the nuclear power industry. Those articles reported on independent unrelated events. However, when read together, they reveal two contrasting directions of the nuclear power industry.

Three Mile Island

The first article, entitled Three Mile Island Nuclear Plant to Close, Latest Symbol of Struggling Industry, could be considered to be the closing chapter of the Three Mile Island nuclear power accident that occurred 40 years ago.

Three Mile Island Nuclear Generating Plant
Source: npr.org

General Public Utilities (GPU) built the Three Mile Island Nuclear Generating Plant, located close to Harrisburg, Pennsylvania, in the early 1970s. Large base load nuclear power plants, like Three Mile Island, were supposed to be the perfect answer for our electricity hungry economy. Nuclear plants do not emit pollutants. And the electricity produced by those plants was expected to be exceedingly cheap. The Chairman of the Federal Power Commission was supposed to have said that production of electricity from nuclear power was “going to be so inexpensive it would not even have to be metered.”

But nuclear power did not turn out to be inexpensive. In fact, because of design changes found to be required during construction, it turned out to be an extremely expensive source of power. In addition, because of the recession of the 1970s, industrial electric consumption was lower than anticipated. There was, therefore, a question of whether the new plants were even needed. By the late-1970s consumer advocates were urging regulatory agencies to order utilities to discontinue construction of their nuclear power plants and keep the costs out of regulated rates.

The Three Mile Island Accident

The regulators were not initially sympathetic to consumer advocates’ arguments. They did not order the discontinuation of construction. They typically approved rates that included recovery of the nuclear plant costs. However, that all changed on March 28, 1979, when an accident in Three Mile Island’s Unit 2 caused a partial melt-down of the nuclear fuel rods.

After the accident those that opposed nuclear power because of its impact on rates were joined by those that opposed nuclear power because of their concerns with its safety. This time the opposition was effective. Utility orders for 120 nuclear reactors were cancelled as virtually all plans for new plants were abandoned.

Even through new construction was halted, plants that were already in operation lived on. In the United States there are still 60 nuclear power plants with 98 reactors in operation. This includes Unit 1 at Three Mile Island which was not damaged by the 1979 accident. In 2018 these 98 reactors produced about 20% of the nation’s electricity. And most importantly, they produced that electricity without emitting any carbon dioxide or other greenhouse gas.

The Impact of Deregulation

With all of the concern about climate change it would seem to make sense to find a way to retain, if not to expand, nuclear power’s share of the nation’s electric production. However, things have changed since 1979.

When Three Mile Island went into service generation, transmission and distribution facilities were all considered to be part of GPU’s regulated system. Under the regulatory compact GPU could decide what type of generation facilities to build and, for the most part, its regulators would authorize the recovery of costs through regulated rates.

However, since the Federal Energy Regulatory Commission issued its Open Access Orders in 1995, most generation is no longer considered to be part of a utility’s regulated system. Now, most utilities cannot expect to recover all costs of generation through regulated rates. Instead, for entities that own generating facilities, that service is competitive and the costs can only be recovered if the plant successfully competes with other sources of electric production.

The Future for Plants Like Three Mile Island

Three Mile Island Unit 1 is typical of nuclear generating plants located in areas where generation is now a competitive service. It has, in recent years, struggled to remain competitive with electricity produced by renewables and low cost gas produced by fracking. Now these nuclear units are at an age when they need expensive upgrades to continue in operation. The current competitive prices for electricity do not support the cost of those upgrades.

As explained in the NPR article, Exelon, the current owner of Three Mile Island Unit 1, sought subsidies from the Commonwealth of Pennsylvania to keep the plant in operation. However, Pennsylvania did not agree to the subsidies and Exelon announced the closure of Unit 1 effective in September, 2019.

The fate of Three Mile Island Unit 1 likely reflects the fate of most of the other large base load nuclear generating plants. Owners that are unable to recover costs either through regulated rates or government subsidies are retiring the plants.

And there is little likelihood that anyone is going to build new large base load nuclear generating plants. The only such plant currently under construction is Vogtle Units 3 and 4. These plants, if completed, will be owned primarily by Georgia Power Company. Vogtle Units 3 and 4 are turning out to be extremely expensive – current cost projections are expected to exceed $18 billion. Those facilities rely on huge government subsidies and Georgia Power’s continuing ability to recover its generation costs through its regulated rates. In the absence of the subsidies and regulatory rate recovery this type of facility would be very difficult, if not impossible, to finance and construct.

A New Type of Nuclear Power

Although it appears that large scale base load nuclear generation is going to be used less and less, the second article on the NPR web site – entitled This Company Says the Future of Nuclear Energy is Smaller Cheaper and Saferdescribes a different type of nuclear generation that may be ready to take its place. This second article describes the efforts of an Oregon company, named NuScale Power, to build smaller, simpler and less expensive nuclear generating plants. NuScale plans to build these modular plants at its plant and to ship the completed plants to their points of use.

NuScale contends that its plants are safer than traditional nuclear plants because they do not rely upon pumps and generators – which can fail in the event of an emergency – to provide cooling for the reactors. Instead, the reactors are located in a containment vessel in a pool of water which provides passive cooling. The following video depicts the unique operation of the NuScale plant.

NuScale claims that its plants can be used either jointly as a base load facility or as a small scale back-up for the intermittent generation from a wind or solar farm. NuScale further claims that its generation will be less expensive than electric storage, the other electric source commonly considered as a back up to renewables.

NuScale currently has plans to install its first nuclear plant at the Idaho National Laboratory in 2026. Power from the plant will be used to operate the Lab and sold to the Utah Associated Municipal Power Systems for resale its members’ 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. 

Distributed Generation – an Old Idea Reconsidered

Development of Central Station Generation

In 1882 Thomas Edison brought electric light to an office building located in New York’s financial district. He used electricity generated at a dynamo located close the point of use. While he did not know it at the time, his use of a small generator located close to the point of use would one day be referred to as “distributed generation.”

Edison's first form of distributed generation
Edison’s Pearl Street Generating Station
Source: alchetron.com

Edison hoped to “light the world” with duplicates of his business model. However, his use of multiple small generators was expensive and inefficient. George Westinghouse saw the shortcomings of Edison’s system. With Nicola Tesla’s help Westinghouse developed an alternating current system that used large remote central station generating plants. Westinghouse used transformers and long distance high voltage transmission lines to deliver the electricity generated by these plants . Because Westinghouse’ system was much more efficient than Edison’s he won the Electric Current War.

Remote central station power plants using a complex delivery system of transmission lines are now the standard in the industry.  And distributed generation fell out of favor for more than 100 years.

Flaws of the Central Station Model

The current system is not, however, without its own problems. The fossil fueled central station plants emit pollution and greenhouse gases. And, because of their size, the central station plants must be added in large chunks, often before they are needed by utility customers.

The transmission system used to deliver the power is also an issue. It requires rights-of-way in controversial areas, is maintained by utilities with varying levels of commitment to that maintenance, is subject to potential outages due to weather, faulty equipment and terrorist attacks and results in energy losses of as much as 10%. Even with these flaws, however, for more than 100 years, Westinghouse’ system has been used for the delivery of reliable and affordable electric service.

Reconsideration of Distributed Generation

Reliance on large central station generation may, however, be changing. Distributed generation, similar to what Edison used in his early lighting systems, may be an efficient substitute for at least some portion of the current system.

Distributed generation can come in the following forms:

  • Back-up generation that ensures continued operation during an outage of the larger grid. Many health care facilities have historically used this type of distributed generation. But more residential and commercial facilities are starting to adopt its use.
  • A combination of generation sources (possibly including small scale thermal generation along with one or more renewable resources) that can provide service to a major institution such as a university, a hospital or a government campus, as well as the surrounding community. This is sometimes referred to as a micro-grid. It can operate either along with, or independent from, the larger grid.
  • Site specific generation, such as an industrial facility’s cogeneration plant or residential roof top solar panels where a portion of the energy generated can be sold to the larger grid.
  • Behind the meter generation where the output is used solely to reduce the owner’s purchases from their local utility.
Rooftop solar as distributed generation

Source: weforum.org

The United States Department of Energy paper entitled The Potential Benefits of Distributed Generation and Rate-Related Issues That May Impede Their Expansion provides a more detailed discussion of the various forms of distributed generation.

Distributed Generation Can Provide Both Individual and System Benefits

Customers who see a benefit are likely to install distributed generation for their own use. But, distributed generation can also provide benefits to the overall utility system in the form of reduced losses, reduced pollution from central station thermal plants and improved system reliability.  There should be a way to encourage installation of distributed generation to provide these benefits. But, utilities like to rely on their own large scale generation plants. So, historically, they have discouraged customers from installing distributed generation.

In recent years, however, regulatory agencies have reduced the utilities’ ability to discourage customer installed distributed generation. And utilities seem ready to capitalize on the potential benefits.

Utilities will not, however, fully realize the system-wide benefits of distributed generation until they fully incorporate their operation into their system operations and planning. And that will not occur until they fully implement the Smart Grid.

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.