President Roosevelt Takes on the Power Trusts

Creation of Monopoly Utilities

After George Westinghouse and his alternating current won the Electric Current War electric companies began providing service from central station power plants and networks of transmission and distribution facilities. But well financed electric companies who built the biggest facilities produced electricity at the lowest operating costs. These companies undercut the prices of their smaller competitors. Those smaller companies either went out of business or submitted to mergers.

Eventually the large electric companies became monopoly electric suppliers in their local areas. States passed laws implementing regulatory control over the electric utilities to prevent them from from charging exorbitant rates.

Development of the Power Trusts

State regulation did not, however, prevent the monopoly electric utilities from merging with each other to become even larger regional and national electric suppliers. These growing companies purchased many of their goods and services from affiliated coal companies, engineering services companies and administrative services companies.

Each conglomerate, consisting of multiple local electric utility companies and their suppliers, was referred to as a Power Trust. By the early 1920s eight Power Trusts provided 73% of the country’s electric service.

Use of the Holding Company Structure

The Power Trusts all utilized the Holding Company structure. The Holding Company structure enabled a small group of rich men use investments from many small investors to build a large business empire. The men who controlled the Power Trusts made sure that they grew rich while the Power Trusts made money. But if there ever came a time when the Power Trusts did not make money it was the small investors who were likely to lose their investment.

The potential risk to small investors was not the only problem with the Power Trusts. The local electric utilities in the Power Trusts paid inflated prices for the goods and services they purchased from supplying companies within the corporate family.  State regulatory agencies had difficulty regulating these inter-affiliate transactions. They resulted in increased rates for electric ratepayers.

The potential risk for small investors came to fruition in the Depression of 1929. The electric utility companies within the Holding Company structures did not generate enough revenues to pay down Holding Company debt. So the small investors lost their investments. The Power Trusts were weakened. But they were not dead. The small group of men that controlled the Power Trusts were just waiting for the economy to improve so that they could rebuild their empires.

President Roosevelt Opposes the Holding Companies

When Franklin Roosevelt was elected President in 1932 he promised that he would prevent the Power Trusts from regaining their power. He would have liked to have outlawed the Holding Company structure with legislation that prevented outside ownership of local electric utilities. But he recognized that there were some benefits to some common ownership of utilities. He, therefore, supported legislation that regulated, rather than eliminated, Holding Companies.

The men that controlled the Power Trusts did everything they could to oppose the legislation. They hired a team of 600 lobbyists to try to convince congressmen to vote against the legislation; they sent forged letters opposing the legislation to congressmen allegedly from their constituents; and they even started rumors about President Roosevelt’s sanity.  Thomas McCarter, President of the Edison Electric Institute, referring to Roosevelt’s opposition to Holding Companies said

The President has an obsession on this subject. It is a condition of mind that even his closest associates in Washington do not understand.

The Public Utility Holding Comany Act of 1935

Notwithstanding all of this opposition President Roosevelt got his legislation regulated the Holding Companies. It was called the Public Utility Holding Company Act of 1935 (PUCHA). PUHCA made the Security and Exchange Commission (SEC) responsible for implementing its regulatory requirements.  For a more detailed description of the passage of PUHCA see the linked entry in encyclopedia.com.

PUHCA imposed numerous requirements on Public Utility Holding Companies. For example, it limited the breadth of Holding Company ownership by prohibiting ownership of utilities in non-adjoining states absent an economic justification. It prevented the controllers of Holding Companies from taking advantage of small investors by requiring full disclosure of the ownership structure.  And it required any sales from non-utility affiliates to utilities to be at cost without inclusion of any profit.

Immediately after passage of PUHCA 759 utilities were separated from their Holding Company structures and began to operate as stand alone companies responsible solely for serving their customers rather than generating profits for the Holding Company controllers. By 1952 virtually all Public Utility Holding Companies had ceased to exist.

The utilities long sought to have the PUHCA repealed. In 2005 they were successful with the repeal contained in the Energy Policy Act of 2005 (EPAct 2005). However, EPAct 2005 did not eliminate all of the consumer and investor protections contained in PUHCA. Many of such protections were retained and transferred to the regulatory oversight of the Federal Energy Regulatory Commission.

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. 

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. 

Could Increased Electricity Usage be the Answer to Climate Change?

Greenhouse gas emissions from the transportation and heating sectors

Fossil fuels used in the production of electricity produce 28% of our greenhouse gas emissions. One would think that reducing our electricity usage would reduce our greenhouse gas emissions. But, some experts suggest that just the opposite is true. They say that we can reduce our greenhouse gas emissions by increasing our electricity consumption for electric vehicles and heat pumps.

Reducing electricity usage would reduce the greenhouse gas emissions associated with the production of electricity. However, electricity is not our only source of greenhouse gas emissions. 

Source: USEPA

We use fossil fuels for 90% of our transportation requirements. And we use fossil fuels for almost all of our residential and commercial heating requirements. This usage accounts for 29% and 12% of greenhouse gas emissions respectively. We can reduce greenhouse gas emissions in these sectors only by reducing their use of fossil fuels. In both cases electricity is the only available alternative to fossil fuels.

Electric Vehicles

Many experts view electric vehicles (EV) as the best way to reduce greenhouse gas emissions in the transportation sector. And state and federal governments are already offering incentives for drivers to purchase EVs. However, only 2% of new cars sold in America are EVs. Buyers have been slow to embrace EVs because of the following:

  • Time it takes to charge the vehicle;
  • Range of driving on a single charge;
  • Cost as compared to conventional cars; and
  • Lack of charging stations.

The automobile industry is working on these issues. And it will probably resolve them within the next several years. However, even if the American public fully embraces EVs, there is a question of the extent to which EVs will actually benefit the environment.

EV tailpipe emissions (including emissions associated with electricity used to charge the battery) are less than conventional auto tailpipe emissions. But tailpipe emissions are not the only source of greenhouse gas emissions. The “well to wheel” emissions – that is, tailpipe emissions plus the emissions from electricity required to produce the automobile – must also be considered. And, because of the electricity required to produce the EV battery, it takes more electricity to produce an EV than to produce a conventional auto.

Based on today’s mix of electricity production facilities the “well to wheel” emissions for EVs may actually be greater than for conventional autos. We will not, therefore, get the full benefit of EVs until more electric production is converted from fossil fuels to renewables.

Heat Pumps

Historically, we have used fossil fuels for almost all of our space heating requirements. But, during the 1970s there was a perception of a natural gas shortage. Without the availability of natural gas we started to use heat pumps fueled by electricity for space heating. After natural gas was once again readily available, heat pumps fell out of favor. In many cases the heat pumps installed in the 1970s were removed and replaced by conventional fossil fueled furnaces. Today, we get virtually all of our space heating from furnaces fueled by natural gas, oil or propane.

Now, with fossil fueled furnaces identified as a source of greenhouse gas emissions, heat pumps are getting a new lease on life. Heat pumps operate in the same way as air conditioners. In an air conditioner the hot air inside the home is transferred to a coolant which is condensed and compressed to transfer the heat outside. In a heat pump the hot air outside the home is transferred to a coolant which is condensed and compressed to transfer the heat inside. Although it may seem counterintuitive, outside air that is as cool as 32 degrees Fahrenheit contains enough hot air to be useful in a heat pump operation. When the outside air goes below 32 degrees the heat pump must use some type of auxiliary heating system to heat the indoor air.

The following video explains the operation of a heat pump:

Heat pumps operate on electricity. And electricity generation produces greenhouse gas emissions. However, even with today’s mix of electric generation facilities, the greenhouse gas emissions from the electricity used to run a heat pump are less than the greenhouse gas emissions produced from a fossil fueled furnace. And the greenhouse gas emissions associated with heat pump usage will further decrease as more electric production is converted from fossil fuels to renewables.

Conversion to EVs and Heat Pumps

No one is going to ask us to immediately replace our conventional autos and fossil fueled furnaces with electric vehicles and heat pumps. In fact, until more of our electric generation comes from renewables the electrization of the transportation and space heating sectors might have limited benefits. Therefore, conversion to electric vehicles and heat pumps should occur over the next 10 or 20 years in parallel with the greening of electric production.

It should also be noted that the current electric generation mix is geared towards meeting a peak demand that occurs on hot summer afternoons when air conditioners are in use. The increased electric consumption associated with the electrization of the transportation and heating sectors could cause a shift in the electricity load curve. This shift will have to be accommodated as new generating plants are added to the system.

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 Rural Electrification Act Brings Electricity to America’s Farms

Rural Life Without Electricity

It did not take long after Edison invented the first incandescent light bulb for private companies to commence providing electric service to most urban communities in the United States. Modern appliances like refrigerators, vacuum cleaners and radios were soon transforming the lives of urban residents. But rural electrification was not occurring at the same pace.

In the early 1900s electricity was not available in rural areas. Private electric companies claimed that it was too expensive to string their lines over the miles between farms. And where electricity was available to farms it cost almost twice as much as in urban areas.

By the mid-1930’s only 10% of rural areas had access to electricity. The lives of rural residents were not being transformed by electricity. In fact, most lived just like their parents and grandparents had. Farmers milked their cows by the light of a kerosene lamp. Their wives cooked their meals and warmed their water on a wood-burning stove. And their produce was vulnerable to spoilage because of lack of refrigeration.

Federal Support for Rural Electrification

Franklin Roosevelt understood the plight of the farmers. When he was governor of New York he had promoted development of the New York Power Authority, a state agency that produced low cost hydropower on the St. Lawrence River for use in rural areas in New York. When Roosevelt was elected President he invited Morris Cooke, who had led Giant Power, the Pennsylvania rural electrification program, to develop a federal government response to the lack of electricity in rural America.

Based on Morris’ recommendations Roosevelt created the Rural Electrification Administration (REA) in 1935. The REA was given authority to loan funds at low interest rates for construction of the infrastructure required to provide electricity to rural areas. It was initially thought that REA would loan the funds to private utilities for construction of the infrastructure. However, the private utilities continued to show little interest in serving rural areas.

Formation of Rural Electric Cooperatives

In 1936 Congress passed the Rural Electrification Act. The Rural Electrification Act gave the REA additional funding and directed it to make the low cost loans to cooperatives made up of residents of the rural communities. After passage of the Rural Electrification Act local residents joined together to form Rural Electric Cooperatives. The residents became both the owners (or members) and the customers of the Rural Electric Cooperatives. The Cooperative members elect a Board of Directors which hires the management team and employees to run the cooperative system.  

The Rural Electric Cooperatives used the funds borrowed from the REA to construct their own electric distribution systems. Their cost for construction was far less than it would have been if the private utilities had provided the same service.  Where available the Rural Electric Cooperatives purchased their electric generation from federal hydroelectric power projects or from private electric utilities. Where generation was not available from other sources the Rural Electric Cooperatives joined together to form Generation and Transmission cooperatives that built generation facilities for their cooperative members. 

The Rural Electrification Act was one of the most successful federal programs ever implemented. By the mid-1950s over 90% of rural homes in the country had electricity. In 1994 Congress replaced the REA with the Rural Utility Service which continues to make low cost loans to Rural Electric Cooperatives.  Today 99% of rural homes have electricity. Most are served by one of the 900 Rural Electric Cooperatives that continue in operation today.

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. 

What is a Microgrid?

Definition of a Microgrid

The Electrical Grid is defined as “the electrical power system comprised of generating plants, transmission lines, substations, transformers, distribution lines and end-use customers.” A Microgrid can be viewed as a miniature version of the Electric Grid. Specifically, a Microgrid is defined as “a localized group of interconnected generation resources and end-use customers that operate as a single controllable entity.” For more technical details on Microgrids see Microgrids at Berkeley Labs.

Some Microgrids consist of only a single electric user’s distributed generation and consumption. An industrial site, an educational institution or a hospital would be a good site for a single user Microgrid. Other Microgrids consist of the distributed generation and consumption of a community of electric users. This second type of Microgrid is often referred to as a milligrid. The important point, however, is that Microgrids must be controlled and operated as unified systems.

The following video describes how a Microgrid works:

Benefits of a Microgrid

The critical feature of a Microgrid is that the operator monitors and controls all of its distributed generation and electric customer usage. Microgrids are interconnected to the larger electric grid and viewed by the interconnecting utility as a single customer point of interconnection. Microgrids can purchase back-up power from the utility and it can sell excess generation to the utility. However, in the event of an outage on the utility system the Microgrid can disconnect and operate as an “electrical island”.

Electric customers participating in a Microgrid receive the benefits of a secure source of electric supply, efficient operation of their distributed generation and reduction in transmission line losses. The benefits available from Microgrid operation are similar to those that a utility might gain from installation of the Smart Grid.  However, it is easier to implement a Microgrid because of its smaller scale and the voluntary interest of the participants.

While utilities are starting to get into the business of operating Microgrids many are now being operated by non-utilities. The ability to operate the Microgrid as an electrical island raises the possibility that the operator may, at some point, opt to simply disconnect from the utility system if they no longer see advantages from further connection. This potential for disconnection is one of the concerns raised in the Post entitled What is 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. 

What is the Smart Grid?

Electric Consumption and the Arab Oil Embargo

Prior to 1973 the electric industry encouraged customers to consume electricity. More consumption meant more efficient large central station generating plants. More large central station generating plants meant lower operating costs and lower electric prices. And lower electric prices fueled the post-war economic boom.

But the 1973 Arab Oil Embargo was a wake up call. While coal or nuclear fuel were used for most large base load plants the smaller plants used to meet peak customer demand were fueled by foreign oil. And deliveries of that foreign oil could cease without notice. Thus, reliability of electric service was, at least in part, subject to the whims of foreign powers. After the Oil Embargo it was no longer good policy to just encourage electric consumption.

Confronting the System Peak

Electrical consumption throughout the day looks like following graph of typical load curves. This graph shows that, especially in the summer, usage peaks towards the late afternoon.

Typical daily load curve
Source: fsec.ucf.edu

Reducing the system peak reduces use of the oil-fueled peaker units. Less reliance on peaker units means less dependence on foreign oil, fewer emissions from oil-fired generation and lower cost electricity. The industry and its regulators now seek ways to “shave the peaks”.

The main weapon in the fight to shave the peaks has been demand side management programs. These programs encourage customers to reduce their consumption during the time of the system peak. The demand side management programs have succeeded in reducing customer peak demand. However, primarily because of the increased air conditioning load, the peaks remain.

The Smart Grid Will Turn Utility Service to a Two-Way Street

Many in the industry now believe that the Smart Grid will both revolutionize peak shaving capability and help to resolve numerous other challenges facing utility operations.

Electric service has, historically, been a one-way street – utilities generate electricity and transmit it their end-use customers. The Smart Grid will make electric service a two-way street. Utilities will still deliver electricity. But they will also use new technologies to monitor and control all aspects of the electric system. This includes their own transmission and distribution systems as well as customer-owned distributed generation and storage and all components of customer usage.

With the consent of their customers the utilities will be able to control customer owned distributed generation and usage to most efficiently manage their system for the benefit of all. The following video shows how the Smart Grid will work:

The Benefits of the Smart Grid

The potential benefits of the Smart Grid include the following:

  • Utilities will deliver real time pricing information to customers who will be able to respond by reducing consumption during high cost periods of the system peak.
  • With customer consent utilities will be able to directly reduce individual customer usage during the time of the system peak.
  • When peak usage is reduced, either through customer action or utility action, generation costs are reduced for the entire system.
  • The utilities will be able to dispatch and use customer owned distributed generation and electrical storage to meet peak demand when needed by the system.
  • Incorporation of customer owned generation and electrical storage will reduce emissions from central station power plants and reduce transmission losses.
  • Power quality required for digital applications will be improved.
  • Outages, no matter what their cause, can be immediately detected and fixed.

Financing the Smart Grid

It is generally accepted that adoption of a Smart Grid will benefit the utilities, their customers and the public in general. Components of the Smart Grid will, presumably, be installed by the utilities and become part of utility operations.

In a study conducted in 2011 the Electric Power Research Institute (EPRI) estimated that the cost of the Smart Grid would be $476 billion. EPRI also estimated that the payback would be 2.6 to 6.0 times that amount.

Utility costs are typically passed along to customers in the form of higher rates. However, even though there are clearly benefits to be gained from the Smart Grid, there is a question of whether the Smart Grid costs should be treated like other utility costs.

Many electric customers already have the option of terminating their utility service by using distributed generation or participating in a micro-grid. If their utility rates increase because of the cost of the Smart Grid they may opt to disconnect from the utility to avoid the higher rates.

The benefit of the Smart Grid comes from the utility having access to customers that remain on the grid. If customers start to leave the system to reduce their costs the utility will have access to fewer customers. Thus, the benefit will be reduced and there will be fewer customers to share the Smart Grid costs. See the paper entitled Paying for the Smart Grid by Luciano De Castro and Joisa Dutra for an in depth discussion of financing the Smart Grid.

This financing issue will have to be resolved before we can receive all the benefits that the Smart Grid promises  to provide.

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. 

The Electric Current War

Thomas Edison Uses Direct Current for his Lighting System

Thomas Edison’s wanted to grow rich while “lighting the world.” He could not, however, achieve his goal until he fought and won the Electric Current War.

On September 4, 1882 Edison flipped a switch and lit 400 electric light bulbs in an office building in New York’s financial district. He had beaten all other inventors that were trying to develop a usable incandescent light bulb.

Thomas Edison used a direct current system to power his light bulb
Thomas Edison
Source: renewableenergyworld.com

Edison was already known as the “Wizard of Menlo Park” for his work with the phonograph and the kinetoscope. But Edison wanted to be more than just an inventor. He wanted to be one of the industrial titans of the age.

Edison lit his first 400 bulbs with electricity generated at a dynamo located just across the street from the bulbs. Edison had no choice but to place his generator close to his point of use. His system used direct current in which electricity flows in a single direction. Direct current electricity operates at very low voltages and low voltage electricity loses its effectiveness over short distances. If he located his generator too far from the point of use the generated electricity would be too weak to light the bulbs. 

None of this bothered Edison. He just sold lighting systems that relied upon generators located close to the point of use. Each time that Edison wanted to light a factory or an office building he had to install a new generator for that facility. 

George Westinghouse Uses an Alternating Current System to Compete with Edison

George Westinghouse made his fortune off of his invention of the train air brake system. While Edison was expanding his lighting business George Westinghouse was living in his Pittsburgh mansion looking for his next business opportunity. He well understood the inefficiencies of Edison’s direct current system.

George Westinghouse competes with Edison in the Current War with his alternating current system
George Westinghouse
Source: westinghousenuclear.com

Westinghouse learned that some European inventors had invented something called a transformer. He knew transformer could be used to increase the voltage of alternating current and transmit it for many miles. Westinghouse developed an alternating current system consisting of large central station generating plants, transformers and high voltage transmission lines. The following video explains the differences between direct current and alternating current:

There was, however, a problem with Westinghouse’ system. The motors of the day were designed to operate on direct current rather than alternating current. Westinghouse teamed up with an eccentric Serbian genius named Niclola Tesla to develop motors that could operate on alternating current.

Nicola Tesla designs a motor that helps Westinghouse compete in the Current War.
Nicola Tesla
Source: nationalmaglab.org

Beginning in the mid-1880s Edison and Westinghouse engaged in a competition for customers with their respective direct current and alternating current systems. Their competition was well publicized. The press called it the Electric Current War.  

The End of the Electric Current War

Westinghouse’ system was more efficient and less costly than Edison’s. Edison could have acknowledged the benefits of Westinghouse’ system and adopted a form of the alternating current system for himself. In fact, Edison’s investors encouraged him to abandon his direct current system. But Edison stubbornly fought for his direct current system. To try to defeat Westinghouse he engaged in a public relations campaign that accused Westinghouse’ high voltage system of endangering the public. 

The Electric Current War ended in 1892 when, without Edison’s knowledge,  J.P. Morgan engineered a merger of Edison’s company with another firm that was already using a form of the alternating current system. The merged firm was renamed the General Electric Company. Those who like cinema may also like to know that this story has been made into a major motion picture called The Current War in which Benedict Cumberbatch plays Thomas Edison.

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. 

Is a Carbon Tax the Answer to Climate Change?

Increasing Interest in a Carbon Tax

Fossil fuel combustion causes 82% of the greenhouse gas emissions in this country.  Those that believe that human activity causes climate change agree that we must reduce those emissions. While there is no consensus on how to achieve these reductions support has been growing for a carbon tax. See the Environmental Defense Fund’s explanation of a cap and trade program, which is another viable method to reduce greenhouse gases.

Pollution from power plant that could be reduced with carbon tax
Source: butane.chem.uiuc.edu

A carbon tax is a fee imposed on the burning of fossil fuels. Such a fee forces users of carbon-based fuels to pay for the detrimental impact on the environment of their use.  For a detailed explanation of how a carbon tax might be used to reduce greenhouse gas emissions visit the Carbon Tax Center web site.

Forms of a carbon tax are already in effect or proposed in numerous countries including England, Ireland, Australia, Chile, Sweden, Finland and New Zealand. Forms of a carbon tax are also in effect in 10 states. And several bills have been introduced in Congress which would implement a national carbon tax.

How a Carbon Tax Would Work

There are numerous versions of a carbon tax. However, in this Post I will focus on a form of the tax that is assessed at the time that fossil fuels are mined or imported into the country. Presumably, those that pay the tax will pass the cost along in their sales price. Ultimately, the cost of the tax will be reflected in the of the price of gasoline and electricity.

The tax would also affect the cost of certain plastics that use fossil fuels but capture the carbon and do not emit greenhouse gases. This use of fossil fuels does not add to greenhouse gas emissions. Therefore, most carbon tax proposals provide credits for such plastics that zero out the cost of the tax.  

Impact on the Price of Electricity

Electric power production from coal, oil and natural gas causes one-third of the greenhouse gas emissions associated with fossil fuels. If a carbon tax is enacted the cost of electricity produced by coal, oil and natural gas will undoubtedly increase.

Opponents of a carbon tax base most of their opposition on the impacts that these price increases could have upon the economy.  For a good argument against a carbon tax see the article entitled 10 Reasons to Oppose a Carbon Tax on the American Energy Alliance web site. For a detailed discussion of the impact of a carbon tax see the paper entitled Effects of a Carbon Tax on the Economy and the Environment prepared by the Congressional Budget Office.

Opponents of the carbon tax contend that the cost of the tax will simply be passed along to electric customers in the form of price increases. However, such an argument does not fully consider the operation of deregulated markets that govern most of today’s electric consumption.

In the competitive markets each regional Independent System Operator (ISO) manages a power exchange where electricity is bought and sold. Hundreds, or even thousands, of generating plants participate in each of these ISO markets. These plants operate on fossil fuels, nuclear or renewable resources.  They all hope to sell their production to the market at or above their operating costs.

Each ISO follows a set of rules that dictates the order in which it will purchase power from these plants. These rules require the ISO to dispatch the plants in reverse order of their cost of production. Thus, during hours when electric consumption is low the ISO will dispatch only the lowest cost production. The ISO will dispatch higher cost production only during hours when consumption increases.

The following graph shows how an ISO dispatches different types of generation at different prices as consumption varies throughout a 24 hour period:

Carbon tax could impact economic dispatch position of fossil fuel plants
Source: pjm.com

As can be seen from the above, the ISO dispatches low cost renewable and nuclear power during low usage hours.  The ISO adds more expensive natural gas combined cycles, coal and combustion turbine oil plants only during higher usage hours.  

If a carbon tax causes the fossil fueled plants to become expensive it would certainly increase the price of electricity during hours when those plants are in operation. However, there is good reason to believe that the fossil fueled plants’ hours of operation may decrease. Their increased operating costs should increase opportunities for additional renewables to compete, and be dispatched, at price levels that are lower than the new cost of fossil fueled generation. This would limit the use of fossil fuel generation to hours when consumption reaches very high levels. In other words, the carbon tax would increase renewable generation and reduce the hours in which high priced fossil fueled generation is in use.

The Level of the Carbon Tax

One argument against a carbon tax is that it constitutes a political decision to force certain behavior – in this case reduced use of fossil fuels. However, it could also be argued that the current failure to recover the societal cost of carbon usage from its users constitutes a political decision to subsidize the use of fossil fuels.

The Environmental Defense Fund estimates that the detrimental societal cost of carbon usage is currently around $40/ton of carbon dioxide. Other estimates are both higher and lower. However, whatever the true cost of carbon emissions, it would seem that that cost should be borne by the carbon users rather than by society in general. Implementation of a carbon tax that at least equates to the societal cost of carbon usage would not be a new political decision. It would reverse an existing political decision to subsidize fossil fuel use.

Where Will the Revenues Go?

Revenues from a carbon tax could be substantial. Estimates are that a modest tax of $15/ton of carbon dioxide would result in $80 billion in tax revenues. There is a question of how that $80 billion should be used. Suggestions include using the funds to reduce the national debt, using the funds to finance renewable generation projects, and using the funds as tax credits for low income families to partially offset the increased costs of gasoline and electricity caused by the tax. Any carbon tax legislation will have to include the answer to the question of where the tax dollars go.

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. 

Is the Utility Death Spiral for Real?

Causes of a Utility Death Spiral

For over 100 years the government has guaranteed utilities a reasonable operating profit. However, current conditions have led utilities to the precipice of a death spiral.

The regulatory compact, embedded in all state public utility acts, requires utilities to provide reliable service to their customers in exchange for a government guarantee of a reasonable return on utility investment. What could be a better promise for a business? Provide a necessary service to customers and receive a steady and reliable return for investors. 

But now there is talk of a utility death spiral. A death spiral can be defined as “a situation that keeps getting worse and that is likely to end badly with great harm or damage being caused.” Is this even possible?

Well the fact is that not only is it possible, it is probably true. Utilities have invested in infrastructure that provides a necessary service. Their government approved rates include recovery of, and a return on, that investment in infrastructure.  

But customers are responding to these rates by installing distributed generation like rooftop solar. This self-generation reduces, or even eliminates, purchases from the local utility. And even though sales go down, the fixed costs of the installed infrastructure remains the same. And those fixed costs have to be recovered from remaining customers. Those costs will be recovered over fewer sales and rates for those sales will inevitably increase.  

Rooftop solar is contributing to the utility death spiral
Source: weforum.org

As rates increase more customers will decide to install their own distributed generation. This further reduces sales by the utility and increases rates for remaining customers. If nothing is done to check this utility death spiral the infrastructure costs will either be paid by the poorest customers who can least afford to install distributed generation or will not be paid at all sending the utility into bankruptcy.

Utility Response to the Death Spiral

Some utilities have responded to the death spiral by seeking to hold on to the status quo. To retain sales, they have opposed government incentives to customers that tend to overprice the value of distributed generation. And to make sure that they recover their fixed costs, they have proposed to “decouple” recovery of fixed costs from sales-based charges. Where decoupling has been approved the utility recovers its infrastructure costs through a fixed customer charge paid by all customers no matter how much electricity they use. 

The utilities’ tactics effectively reduce the benefits of distributed generation for customers. Customers hoping to get the full benefit of distributed generation will opt to disconnect from the grid. At one time disconnecting from the grid would have been almost unthinkable. However, now more and more customers can disconnect by purchasing small scale storage to back up their distributed generation or by joining a micro-grid. The following video describes the operation of such a micro-grid: 

If the utility tactics that seek to stop the death spiral force customers off the grid they will not stop the utility death spiral. They will instead exacerbate it.  

As described in the Post entitled What is the Smart Grid? utilities can achieve significant efficiencies for the entire system if they use a Smart Grid to gain the ability to monitor and control customer owned distributed generation. In other words, it is in the public interest for the utilities to keep customers on the grid and to take advantage of their efforts to use distributed generation. It will be up to utilities and policy makers to determine how the utilities will be able to both meet the public interest and to thrive financially in an environment where their traditional source of revenue (selling and/or transmitting energy) is shrinking. 

For more information on utility response to the death spiral see the Deloitte article entitled Beyond the math: Preparing for disruption and innovation in the US Electric power industry.

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. 

Senator Norris vs. Henry Ford – Prelude to Federal Hydropower

Government Owned Hydroelectric Power

Today there are over 600 Federal hydropower plants located mostly in the Northwest and the Southeast Unites States. Together, these plants produce approximately 3% of the nation’s electric supply. Most of the output from these plants goes to reduce the cost of electricity for publicly-owned municipal utilities and rural electric cooperatives.

Federally owned TVA Norris Dam
Source: tva.gov

But Federal hydropower and its support of publicly owned utility systems was not pre-ordained. It did not occur until after a brutal 1920s era battle between a Senator from Nebraska and one of the richest men in America.

History of the Mussel Shoals Generating Plant

The Federal Government got into the power generation business during World War I when it began construction of a hydroelectric generating facility on the Tennessee River, at Mussel Shoals, Alabama. The Government planned to use the Mussel Shoals electric production to power a nearby munitions facility. But the War ended before the munitions plant was completed and construction on the hydroelectric plant was cancelled.

Congress had to decide what to do with the partially completed generating plant. George Norris, Senator from Nebraska, knew that, in the 1920s, privately-owned electric utilities were not extending service to the very poor rural communities of the Tennessee River Valley.  So residents of those communities were living without the benefits of electricity. Their day-to-day lives were much like the lives of their parents and grandparents in the 18th and 19th centuries. Norris proposed that the Federal government complete construction of the Mussel Shoals generating plant and deliver the low-cost electricity to the surrounding communities.

Senator George Norris
Source: georgenorris.org

But Norris received little support from his fellow Senators. This was the era of the Bolshevik revolution in Russia. And there was fear that that revolution could come to the United States. The Senators were sympathetic to the argument of the utility industry that Government participation in the electric power industry would bring this country one step closer to Communism. Therefore, Congress solicited bids from private entities seeking to take over ownership of the Mussel Shoals generating plant.

Henry Ford Seeks Control of the Mussel Shoals Plant

The highest bidder was Henry Ford. He promised to use the production from the Mussel Shoals plant to industrialize the Tennessee River Valley. He suggested that the Tennessee River Valley would become a “Little Detroit”. Once Ford’s plans became public, land speculators bought up the land near Mussel Shoals and sold it in small lots to local residents. They thought Henry Ford was going to make them rich.

Henry Ford sought control of the Mussel Shoals hydropower project
Henry Ford
Source: biography.com

But George Norris was not ready to give up his fight. He did whatever he could to postpone Congress’ approval of Ford’s proposal. Even though he was fighting to bring a better life to the residents of the Tennessee River Valley those residents were more interested in Ford’s promises of economic development than in Norris’ promises of the availability of low cost electricity. During the years of his fight with Ford, Norris received death threats from residents of Mussel Shoals and, whenever he visited the area, he had to be accompanied by an armed bodyguard.

Eventually, Ford grew tired of the fight and withdrew his bid. Congress then sought to make the plant available to privately-owned utility companies. But those efforts never went anywhere because, throughout the 1920s, Norris continued to fight for Government ownership.

President Roosevelt Makes Federal Hydropower a Reality

Norris finally got his wish in 1932 when Franklin Roosevelt was elected President. One of the first actions of the Roosevelt administration was enactment of the Tennessee Valley Authority (TVA) Act which provided for the Government to construct a series of dams generating Federal hydropower up and down the Tennessee River Valley.

Symbol of the TVA
Source: fineartamerica.com

Those dams control flooding, improve navigation and produce low-cost electricity for the residents of the Tennessee River Valley. The TVA Act was so successful that it was followed by numerous other Federal laws that provided for the construction of all of the Federal hydropower projects that are currently in operation throughout the United States.

The following videos provide additional information regarding Henry Ford’s effort to develop the Mussel Shoals project:

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. 

Government Oversight After the 2003 Northeast Power Blackout

Cause of the 2003 Northeast Power Blackout

The 1965 Northeast Power Blackout left 30 million people without power for up to 13 hours. It was the first time that the public understood that there could be such a large scale loss of this critical service. In response to pressure from the Federal Power Commission the utility industry implemented extensive operational and planning changes. Those changes were supposed to prevent future large scale power blackouts. But, on August 14, 2003, an even larger Northeast Power Blackout occurred.

The 2003 Northeast Power Blackout left 50 million people from Detroit, Michigan to Toronto, Canada without power. It left homes and businesses in the dark and without air conditioning. It stranded workers on subways and on elevators. Commuters were caught in gridlock as street-lights stopped working. And water supply was at risk as electric pumps used to transport the water had no power to operate.

Satellite image of 2003 Northeast Power Blackout
Satellite image showing the 2003 Blackout of the Northeast United States
Source: elp.com

The 9/11 attack on the World Trade Center was still fresh in the public’s mind in 2003. And this looked like another terrorist attack. But terrorists had nothing to do with the 2003 Northeast Power Blackout. It was, instead, caused by a combination of human error and an aging electric grid.

Utility Response to the 1965 Northeast Power Blackout

This was not supposed to have happened. After the 1965 Northeast Power Blackout the electric utility industry promised that they would take action to prevent future wide scale outages.  They created nine regional planning organizations. Those organizations coordinated transmission planning among multiple utility systems. In addition to the planning organizations the industry created the National Electric Reliability Council (NERC) whose role was to develop uniform reliability standards for the industry.  

Policy makers may have thought about government oversight of the utilities’ promises. But the utilities convinced the regulators that they understood the importance of keeping the lights on. They said that they were committed to doing whatever it took to prevent future wide scale outages. They promised voluntary compliance with the standards being promulgated by the NERC. There was no government oversight.   

Failure of Voluntary Compliance

Fast forward 38 years and it turned out that not all of the utilities shared the same commitment to reliability. Instead, many used this time to focus their efforts on maximizing profits in a rapidly deregulating electric industry. 

A prime example was FirstEnergy Corp. FirstEnergy is the current corporate name of what used to be Ohio Edison Company, a local electric utility headquartered in Akron, Ohio. During the late 1990s and early 2000s Ohio Edison acquired Centerior Energy Corporation (consisting of the old Cleveland Electric Illuminating Company and the old Toledo Edison Company) and General Public Utilities (consisting of the old Jersey Central Power and Light, Pennsylvania Electric Company and Metropolitan Edison). 

During the years that it was focusing on its growth FirstEnergy grew lax in its reliability obligations. The 2003 Northeast Power Blackout started when a FirstEnergy-owned high voltage line came into contact with a tree and went out of service. Had FirstEnergy complied with the NERC’s standards the tree in question would have been trimmed and the contact would never have occurred. 

But the failure to trim the tree was not the only issue. A computer system required by the NERC standards should have notified FirstEnergy operators when the line went out of service so that they could take action to prevent the spread of the outage. However, the computer system in question was out of service. And, even if the system had been in service, there have been suggestions that the FirstEnergy operators were not trained in how to respond to receipt of the computer signal.  

The 2003 Northeast Power Blackout was the result of a failure of voluntary compliance. Congress decided that, if we are going to be assured of the reliability of the transmission grid, compliance with reliability standards are going to have to be mandatory.

Implementation of Mandatory Reliability Standards

In the Energy Policy Act of 2005 Congress gave the Federal Energy Regulatory Commission (FERC) authority to enforce mandatory reliability standards adopted by the NERC (now renamed the North American Reliability Corporation). The Act also gave FERC authority to assess penalties of up to $1.0 million per day for failure to comply with the standards.  

Front of FERC building
Source: naturalgasnow.org

FERC established nine Regional Entities who are responsible for enforcing the NERC reliability standards. Those reliability standards include practices required to defend the system again cyber-attacks.

It is never easy for businesses to conform their operations to a new regulatory scheme. However, one would have thought that, when faced with potential penalties in the millions of dollars, the members of the utility industry would have done its best to comply.

FERC gave the industry a phase-in period of several years during which it assessed only nominal penalties for events of non-compliance. After the end of the phase-in period the utilities should have been up to speed. Compliance with the reliability standards should have been part of their day-to-day business. So industry watchers were surprised when, in February, 2019, Duke Energy, a utility owning and operating transmission facilities from Florida to Ohio, was fined $10 million for as many as 125 violations of the NERC standards going back over a period of three years. 

After the 1965 Northeast Power Blackout the utilities showed that they could not be trusted to voluntarily comply with reliability standards where there was no risk of penalty. Unfortunately, it is not yet clear that the utilities are any better with complying with mandatory reliability standards where the risk of penalty for non-compliance is significantly higher.

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. 

Determining Just and Reasonable Electric Rates

The Process for Determining Regulated Electric Rates

The Post entitled What is an Electric Utility? explains why regulatory agencies establish just and reasonable electric rates for regulated electric service. This Post explains how they establish just and reasonable electric rates.

Prior to the 1990s regulated electric service consisted of all three components of service – generation, transmission and distribution. Since the 1990s, regulated service usually consists solely of the transmission and distribution components. The following describes the process for setting just and reasonable rates for the components of service that are regulated.

The regulatory compact, implemented under state public utility acts, requires the applicable state regulatory agency to set electric rates that are just and reasonable. The process for setting just and reasonable rates starts with the following formula that determines the total utility revenue for a 12 month period (referred to as the revenue requirement):

Revenue Requirement        =          Prudently incurred costs of operations + (Reasonable Rate of Return x Investment in Used and Useful Plant)

Therefore, to establish a utility’s revenue requirement, the regulatory agency must first determine the following three rate components:

  • Prudently incurred costs;
  • Reasonable rate of return; and
  • Investment in used and useful plant.  
Regulatory agency setting electric rates
Source: alcse.org

The regulatory agency makes its determinations in a judicial-like proceeding. In that proceeding the utility and other interested parties have an opportunity to present testimony and exhibits that support their respective interpretations of the above three rate components.

Prudently Incurred Operating Costs

Operating costs include things like labor, materials and fuels. The starting point for determining this component is the raw operating costs appearing in the utility’s books and records. Unless it makes adjustments the regulatory agency will use those raw costs in the formula to establish revenue requirement. However, parties participating in the ratemaking process will typically advocate adjustments to the raw data.

Operating costs are included in just and reasonable rates
Costs of operations are recoverable through regulated rates
Source: criticalinfonet.wordpress.com

For example, the utility might argue that the raw labor costs should be increased to reflect a negotiated wage increase that is going to take effect during the rate effective period. And customers might argue that the raw labor costs should be decreased to exclude costs that were incurred by the utility to repair some type of non-recurring equipment outage. Only the regulated agency can sift through these arguments to arrive at the number that will be used for setting rates.

Reasonable Rate of Return

The reasonable rate of return component is a weighted average of the utility’s cost of capital. It includes the interest rate on the utility’s long term bonds, the dividends on any preferred stock, the interest rate on any short term debt and a return on outstanding equity. 

The return on equity is the profit component of the utility’s revenue requirement.  Therefore, the return on equity component includes an adder for the taxes that the utility will pay on its profit. 

The cost of debt and the dividends on preferred stock are usually non-controversial. They can be taken directly from the utility’s books and records.

The return on equity is a bit more controversial. The United States Supreme Court has decided that the regulated return on equity should be equal to the return on investments that have risks that are comparable to the utility’s. Historically, the utility and the other parties presented extensive arguments for their preferred returns on equity. In recent years, however, regulatory agencies have found ways to reduce the contentiousness of this issue. 

Investment in Used and Useful Plant

As with the operating cost component, the investment component starts with net investment in operating plant appearing in the utility’s books and records. Unless the regulatory agency makes adjustments, it will use the raw investment values in the ratemaking formula. However, once again, the parties in the ratemaking proceeding will generally advocate adjustments to these raw investment values. For example, the parties might advocate additions or subtractions for investments in facilities that are expected to be either added to, to removed from, service during the rate effective period.

Return on investment in plant is included in regulated rates.
Return on investment in plant is recoverable through regulated rates
Source: wisegeek.net

The Investment component was very contentious during the 1980s when large new nuclear plants were under construction and about to come on line. Because of diminishing customer electric usage, these plants looked like they might not be needed and were referred to as “excess capacity”. Parties representing customers argued that the investment in the new plants should be excluded from rates because they were not going to be “used and useful” in providing service. Because of the potential that they might not be able to earn a return on their investment in these plants many utilities cancelled plans for their construction.

Conversion of Revenue Requirement to Electric Rates

The regulatory agency uses the the revenue requirement as the total revenues that the utility may recover during any 12 month period. So how is that revenue requirement converted to the electric rates that a customer will see on his bill?

First, the regulatory agency will allocate the revenue requirement equitably among each of its rate classes, typically, industrial, commercial and residential. This is sometimes referred to as “dividing the revenue pie”.

Second, the regulatory agency will use projected customer usage for a 12 month period to convert each rate class’ share of the revenue requirement into electric rate components for that class. The components are, typically, a customer charge, a per-kW demand charge (usually only for industrial customers) and a per-kWh energy charge.

Electric rates approved by the regulatory agency will remain in effect until the regulatory agency changes the rates again. This could be for one year or it could be for many years. During the years that the rates are in effect, if the operating costs, return, investment and customer usage are the same as used in the ratemaking process the utility will earn the profit that was projected in that process.

However, in years when any of these components are different, the utility will earn more or less profit than that which was projected. If the changes reducing profits are sustained the utility will apply for a rate increase. If the changes increasing profits are sustained the regulatory agency or its customers may seek to reduce the rates.

Impact of Partial Deregulation on Electric Rates

Where the generation component of service is available on a competitive basis the customer is considered to be buying only transmission and distribution service from its utility. In that case the regulatory agency uses the above described ratemaking process solely to establish rates for those two regulated services.

However, even where the generation component of service has been deregulated the regulatory agencies have not been relieved of their statutory obligation to ensure that the generation component of electric rates is just and reasonable. Prior to deregulation the agencies applied the above described ratemaking process to determine just and reasonable rates for the generation component. Where the generation component of service has been deregulated they make sure that the rates for that component are just and reasonable by ensuring that the market for generation is truly competitive.

Utility invoices have also been affected by deregulation. Where the generation component has been deregulated the utility and the competitive generation supplier may each issue their own invoice to their customers. This means that customers may receive two invoices for their electric service – one from the utility for the delivery of the electricity and one from the competitive supplier for the actual electricity used. However, in some cases the utility becomes the collection agent for the generation supplier and includes the supplier’s charges as a separate line item on its invoice to its customers.

Even when given the option to purchase competitive generation services, some customers wish to continue purchasing generation from their utility. In these cases, the utility will purchase generation for those customers in the competitive market and include the cost of that generation component as a pass through charge on its invoice.

Additional information on electricity pricing can be found at the U.S. Energy Information Administration publication entitled Electricity Explained: Factors Affecting Electricity Prices.

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. 

What is an Electric Utility?

Direct Current vs. Alternating Current

In the late 1800s and early 1900s there was no such thing as an electric utility. Anyone could become an electric and lighting service provider. A provider could serve one customer, a few customers or a large community of customers. Prices for service were set by private contract between supplier and consumer.

The first arrangements, pioneered by Thomas Edison, used direct current – meaning electricity flowed in one direction on the circuit. In Edison’s business model the direct current flowed a very short distance from a small generating unit to the electric lighting fixtures.

But Edison’s business model proved to be very inefficient. George Westinghouse pioneered a more efficient service model. He used alternating current and transformers to deliver electricity many miles from a remote central station generating station to multiple points of use.

The competition between Edison and his direct current system and Westinghouse and his alternating current system came to be known as The Current War. Westinghouse ultimately won the Current War and his remote central station generating facilities became the standard in the industry

The Emergence of the Monopoly Utility

Well financed suppliers built large efficient central station generating plants and reduced their operating costs. They undercut the prices of smaller suppliers and forced them out of business. And by the early 1920s most communities were served by a single monopoly electric supplier. The monopoly supplier owned the generating stations that produced electricity and the transmission and distribution facilities that delivered the electricity.

The following depicts utility owned facilities and how they were used to deliver electricity from a generating plant to the end-user customer:

The Need for Government Involvement

The existence of a monopoly electric supplier caused some angst for both consumers and suppliers. Consumers wanted to prevent the investor-owned monopolies from charging exorbitant rates. And the investor-owned monopolies wanted to make sure that they did not lose their monopoly status.

The investor-owned electric providers knew that they could not get away with charging excessive rates for long. So they considered giving up some control over pricing in exchange for some protection for their monopoly status. In other words, under the right conditions, they were willing to operate under government regulation.

The Regulatory Compact

Policy makers came up with a concept that balanced the interests of the investor-owned electric suppliers and their customers. They called it the Regulatory Compact.  

The Regulatory Compact is basically an agreement between the utilities and the government.  That agreement deals with both service and rates. The investor-owned electric suppliers agreed to use their facilities to provide service to the public under terms regulated by the government. They became public utilities.

In exchange for the suppliers’ agreement to provide service the government agreed that it would guarantee the utilities a protected monopoly service territory and that it would approve rates that covered the utilities’ operating costs plus a reasonable return on investment. 

Virtually every state has now incorporated a form of the Regulatory Compact into its state Public Utility Act. Each of those Public Utility Acts creates a state agency known as a Public Service Commission or a Public Utility Commission. †

Utility regulatory commission in session
Source: alsace.org

Those state agencies establish utility service territories and rates for retail electric service. The service territories protect the utilities’ monopoly. And the rates for service enable the utility to recover just and reasonable rates defined as their operating costs plus a reasonable return on investment. See Post entitled How Do Regulatory Agencies Set Just and Reasonable Rates? for an explanation of the regulatory rate setting process.

The state public utility acts deal solely with service between utilities and their end-use retail customers. In 1935, with passage of Title II of the Federal Power Act, Congress gave the Federal Power Commission (now named the Federal Energy Regulatory Commission or FERC) authority to set just and reasonable rates for wholesale sales between utilities. Between the state public utility acts and Title II of the Federal Power Act all activity of the electric utilities are subject to some level of utility regulation.

Who Owns the Electric Utilities?

Most of the early electric service providers were owned by private investors. Today, approximately 75% of the electric service is still provided by investor-owned utilities.

In many communities, where there was no private investor providing service, municipalities created their own electric systems. Today, approximately 12% of electric service is still provided by municipally owned utilities.

Electric service was available in most urban areas in the early 1900s. However, by the 1930s, most of the rural areas of the country still did not have electric service. Rural residents were operating their farms just like their parents and grandparents did in the nineteenth century. In 1935, with passage of the Rural Electrification Act, the Federal Government made low cost loans available for customer owned Rural Electric Cooperatives. Those Cooperatives used the borrowed funds to build the infrastructure needed to gain access to electricity. Today, the Rural Electric Cooperatives provide approximately 13% of all electric service.

Source: Sierrclub.org

By the 1990s policy makers determined that there was no longer any reason for the generation component of electric service to be considered a part of the regulated service. Therefore, in 1995 FERC issued its Open Access Orders requiring all utilities to unbundle their generation service from their transmission service and to provide non-discriminatory transmission to all generation owners. Since that time many utilities have sold their generation facilities and now own only transmission and distribution facilities. The transmission and distribution services, sometimes referred to collectively as the “wires service,” remains subject to regulation under the regulatory compact.

Who Owns the Generating Facilities?

photo-plant-gas

Source: sceg.com

Most of the country’s generation facilities are now owned by non-utility Independent Power Producers (IPP). The IPP industry expanded rapidly after 1995 when FERC issued its Open Access Orders. Members of this industry built new facilities and purchased the power plants that were being sold by the utilities. The members or the IPP industry are not utilities and are not governed by regulatory compact. They do not have monopoly service territories and their rates are not regulated by any government agency. Instead, IPPs sell their generated electricity into competitive power exchanges. See Post entitled Electricity Sales in the Power Market for an explanation of sales to these exchanges.

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 describe a different aspect of the past, present or future of the electric industry.