A Brief History of FirstEnergy’s Troubles

Electric utilities probably have the best business model in the world. They sell a needed service, have no competitors and earn a government guaranteed profit. And, even those utilities that have expanded into competitive businesses usually make a decent profit as long as they operate efficiently. But, because of bad luck or bad management or both, some utilities just cannot stay out of their own way. They always seem to have troubles.

That brings us to FirstEnergy. On July 23, 2019 Ohio Governor Mike DeWine signed House Bill 6 into law. HB 6 provided a multi-billion dollar ratepayer subsidy that saved FirsEnergy Solutions from bankruptcy. Almost exactly a year later a Federal Grand Jury handed down an indictment accusing an unnamed energy company of providing $60 million that was used as bribes to assure passage of HB 6.

FirstEnergy was later revealed to be the unnamed energy company. FirstEnergy claims that it did not know anything about a bribery scheme. And the Grand Jury did not indict FirstEnergy as a participant in the scheme. However, long time observers of FirstEnergy’s troubles could not have been surprised by this most recent turn of events.

1978 – FirstEnergy’s Troubles Go Back at Least 40 Years 

I first crossed paths with FirstEnergy’s predecessor, Ohio Edison, more than forty years ago. I was a newly minted attorney working for a law firm in Cincinnati, Ohio. One of our clients owned a steel mill that purchased its power from Ohio Edison. In 1978 Ohio Edison filed an application for an electric rate increase with the Public Utilities Commission of Ohio (PUCO). Our client asked us to intervene in the case on its behalf. I participated on the team that represented the client’s interest.

At the time, Ohio Edison was a medium sized utility headquartered in Akron, Ohio. It served a number of small cities and towns in Northeastern Ohio. Ohio Edison’s service territory meandered among and between other utility service territories in the same region. Sometimes the division between service territories ran right down the middle of a street. 

I do not remember much about the outcome of that rate case. But I do remember that Ohio Edison’s customers were outraged that their electric rates were higher than those of their neighbors served by Ohio Power Company. What these customers did not understand was that, by law, utility rates are based upon the costs of utility service. Ohio Edison’s rates were higher than the Ohio Power’s rates because Ohio Edison’s costs were higher than Ohio Power’s. 

But why would Ohio Edison’s costs be higher than Ohio Power’s? There may have been any number of reasons for this disparity. But the most likely reason was that Ohio Edison was just poorly managed and could not control its costs.

1997 – Ohio Edison Enters the Nuclear Power Generation Business 

Ohio Edision Merges with Centerior Energy to Become FirstEnergy

In 1997 Ohio Edison merged with Centerior Energy under the name of FirstEnergy Corp. At the time Centerior Energy owned Cleveland Electric Illuminating Company and Toledo Edison. After the merger FirstEnergy owned four operating electric utilities – Ohio Edison, Cleveland Electric Illuminating, Toledo Edison and Pennsylvania Power.

Along with the Centerior Energy utilities came the three Centerior Energy nuclear power generating plants – Davis Besse, Beaver Valley and Perry. After the 1979 Three Mile Island accident utilities started to consider nuclear generation a very expensive and risky venture. Many utilities cancelled their plans for nuclear plant construction. Centerior had already suffered financial distress because of its investment in nuclear generation. It had written off $1 billion in equity and had slashed its dividend. Could wading into the nuclear generation quagmire lead to more of FirstEnergy’s troubles?

FirstEnergy Incorporates the Centerior Energy Nuclear Plants Into its Generation Portfolio

But there may have been a method to FirstEnergy’s madness. Utility restructuring was on the horizon. Restructuring meant that utilities would be unbundling their generation business from their transmission and distribution business (referred to collectively as their “wires business”). While the earnings of the wires business would remain limited by regulatory restrictions, the earnings of the generation business would be unlimited. Those earnings would be determined solely by the success of the generating company’s participation in the competitive electric markets. 

Most utilities planned to participate in the competitive electric markets. FirstEnergy created FirstEnergy Solutions (Solutions) to serve as its participant in that business. By merging with Centerior, FirstEnergy helped Centerior out of a financially stressful situation, it acquired additional generation for participation in the competitive markets, it raised the potential for higher earnings for FirstEnergy shareholders and it opened the possibility for big bonuses for management. It seemed like a win-win-win situation for all. What could possibly go wrong?

2000 – FirstEnergy Recovers $6.9 Billion in Stranded Costs Under a Cloud

Ohio Senate Bill 3 Implements Utility Restructuring

In 1999 the Ohio General Assembly passed Senate Bill 3 implementing utility restructuring for Ohio. As expected, SB 3 required Ohio electric utilities to “unbundle” their generating business from their wires business. The wires business remained fully regulated by the PUCO. But the generating business operated in a non-regulated, competitive environment. 

FirstEnergy transferred 13,000 MW of generating facilities (including the Centerior nuclear plants) to Solutions. Solutions was, therefore, a fairly good sized generating company when it commenced participation in the competitive power markets. 

Senate Bill 3 Permits FirstEnergy to Recover Stranded Costs

But SB 3 had a wrinkle. It permitted the utilities to charge their ratepayers “transition charges” to recover something called “Stranded Costs”.  The Regulatory Compact, as embedded in Ohio’s public utility law, permits utilities to recover a reasonable return on their investment in facilities dedicated to utility service.

When the FirstEnergy utilities invested in their generating facilities they had a right to expect the PUCO to approve rates that permitted recovery of a reasonable return over the life of those facilities. But when SB 3 required the utilities to operate those facilities in a competitive market, they had not yet recovered their entire permitted return.

The generation facilities were expected to earn something in the competitive market. But there was no longer any assurance that their earnings would amount to the reasonable return guaranteed by the Regulatory Compact. Stranded Costs were equal to the difference between the utilities’ initially expected regulatory return and the return likely to be earned in the competitive market.  And SB 3 permitted the utilities to recover those Stranded Costs from their ratepayers.

SB 3 directed the PUCO to determine each utility’s Stranded Costs and to establish transition charges for their recovery. FirstEnergy claimed that its Stranded Costs equalled $8.8 billion. It filed an application with the PUCO asking for permission to recover those costs from its customers.

FirstEnergy May Have Influenced the Office of Consumers Counsel’s Position on Stranded Costs

When FirstEnergy asked for permission to recover its Stranded Costs, Ohio Consumer’s Counsel (OCC), Robert Tongren, represented customers’ interests in cases before the PUCO. Presumably, he was preparing to oppose FirstEnergy’s calculation of its stranded costs.  OCC retained La Capra Associates to conduct a study to determine FirstEnergy’s actual stranded costs. The La Capra study showed that adoption of FirstEnergy’s proposal would result in a $3.5 billion windfall for FirstEnergy – i.e. the Stranded Costs were no more than $5.3 billion.  

But OCC did not willingly disclose the results of the Capra study. OCC never presented the results of the study in the PUCO case dealing with FirstEnergy’s Stranded Costs. And, in response to a request for a copy of the study, OCC said that it was protected from production during the litigation. Then, upon being asked for the study after completion of the case, OCC said that the study had been destroyed.

OCC ended up settling the PUCO case with FirstEnergy agreeing that it could recover $6.9 billion of its requested $8.8 billion in Stranded Costs. Ratepayers paid that $6.9 billion through transition charges that were in effect from 2000 through 2005.

When the specifics of the La Capra study were finally made public FirstEnergy’s lobbying activities with Mr. Tongren were called into question. FirstEnergy never faced any repercussions from its possible influence of Mr. Tongren. However, because of the suspicions surrounding this issue Mr. Tongren resigned his position as OCC.

There is one more item of note here. SB 3 said that, once ratepayers paid the approved transition charges, FirstEnergy would be fully at risk for its participation in the competitive markets. In other words, no matter how well, or how poorly, FirstEnergy did in the competitive markets, after collection of the Stranded Costs, it could not expect any more relief from its customers related to its generating facilities.

2002  – FirstEnergy Dodges a Disaster at the Davis-Bess Nuclear Plant

The NRC Requires Special Inspections of Pressurized Water Reactors

Once FirstEnergy owned the Centerior nuclear plants it assumed responsibility for their safe operation. Not every utility would have taken on such risk. But FirstEnergy did. And it lead to more of FirstEnergy’s troubles.

In the 1990s the Nuclear Regulatory Commission (NRC) determined that cracks were developing in the pressurized water reactors of nuclear plants similar to Davis-Besse. In 2001 the NRC directed operators to shut down their plants to perform special inspections by December 31, 2001. The NRC, however, said that it would approve extensions of the inspection deadline for operators who submitted satisfactory justification.

FirstEnergy sought such an extension. In support of its request, it told the NRC that its past inspections were adequate to determine if there was any cracking. It said that, in light of those inspections, it could safely postpone the special inspection until early 2002. Based upon FirstEnergy’s submission, the NRC granted it permission to postpone the special inspection until February 15, 2002. 

FirstEnergy Finds a Hole in its Reactor

When FirstEnergy finally conducted the special inspection it found a “pineapple-sized cavity” in the head of its pressurized water reactor. FirstEnergy had to shut down the plant for two years while it spent over $600 million to repair the damaged head.

The NRC found that FirstEnergy had provided false information in support of its request to postpone the special inspection. It assessed FirstEnergy a $5.45 million fine – the largest fine in NRC history. And the Federal Justice Department opened a criminal investigation into FirstEnergy’s submission of false information. FirstEnergy ended up paying $28 million to settle that investigation.

2003 – FirstEnergy Causes a Wide-Scale Outage that Leaves 50 million People in the Dark

After the 1965 Northeast Blackout the Utility Industry Promised to Prevent any Future Large Scale Blackout

After a wide-scale power blackout of the Northeastern United States in 1965 the electric utility industry promised that it would never happen again. The industry organized into nine regional transmission planning organizations. And it created the National Electric Reliability Council (NERC) whose role was to develop reliability standards and practices.  The utilities promised their regulators that they would adhere to the NERC standards.  

Fast forward 38 years and it turned out that not all of the utilities shared the same commitment to the reliability of the transmission grid. Instead, some of the utilities were distracted by their efforts to maximize profits in a rapidly deregulating electric industry. 

FirstEnergy Fails to Follow Industry Standards

In 2003 there was another wide-scale outage that dwarfed the scale of the first outage. This time 50 million electric users in the Northeastern United States were without power for two days. Investigations led to directly to FirstEnergy. While FirstEnergy was focusing on the integration of Centerior Energy and the problems at the Davis-Besse Nuclear Plant, it grew lax in its compliance with the NERC reliability standards. 

The 2003 Blackout started when a FirstEnergy-owned high voltage line went out of service when coming into contact with a tree. Had FirstEnergy complied with the NERC standards it would have trimmed the tree in question so the contact would never have occurred. 

However, FirstEnergy’s failure to trim the tree was not the only issue. A computer system required by the reliability 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. But at the time of the outage the computer system was out of service. And even if the system had been in service there have been suggestions that the FirstEnergy operators were not adequately trained to know how to react upon receipt of the computer signal.  

Because utilities were not required by law to comply with the NERC standards, no regulatory agency fined FirstEnergy for its role in the outage. However, as a result of FirstEnergy’s failure to comply with voluntary standards, Congress passed new legislation, and the Federal Energy Regulatory Commission (FERC) adopted new regulations, that made compliance in the future mandatory.

2016 – FirstEnergy Gives Up on the Competitive Power Market

FirstEnergy Solutions Participated in a Regional Power Market Managed by PJM Interconnection

Beginning in 2000 FirstEnergy Solutions operated in a competitive power market operated by PJM Interconnection, LLC (PJM). Coincidentally, about the same time that Solutions commenced its operation in that market, I moved to the East Coast and started working for another participant in the same market. 

PJM is a regional transmission organization (RTO) that coordinates the movement of wholesale electricity in all or parts of twelve states and the District of Columbia. PJM’s competitive power market rules are developed by committees of its stakeholders and approved by the FERC. 

Those rules are designed to make reliable and low cost electricity available to ratepayers located in the area that PJM manages. All generating plant owners in the PJM area participate in a series of PJM managed auctions. The plant owners submit prices in those auctions at which they offer to sell their power. Naturally, the bid prices generally reflect the generators’ cost to operate. PJM dispatches the generators in the order of their bids – from lowest price to highest price.

Generators with low operating costs, typically gas-fired and renewable generation, usually clear the PJM auctions and run on a regular basis. Generators with high operating costs, typically coal-fired and nuclear, do not usually clear the auctions and often stand idle.

All participants understand the risks and rewards of the competitive market. Shareholders of companies that sell adequate quantities of power at prices above costs reap rewards. Shareholders of companies that are not often dispatched might lose some or all of their investment. And, unfortunately, the employees of companies that cannot compete sometimes lose their jobs.

FirstEnergy Solutions’ Nuclear and Coal Fired Generation Could Not Compete with Gas Fired Generation and Renewables

It would have been hard to criticize FirstEnergy for its decision to big bet on coal-fired and nuclear generation. After all, coal-fired and nuclear generation were quite profitable during the early days of the competitive markets. At that time few could have foreseen how natural gas fired generation was going to upend the power markets.

However, by 2016, the decision to bet on coal-fired and nuclear generation had led to more of FirstEnergy’s troubles. Solutions was facing the same challenges as other owners of nuclear and coal-fired generation. The costs of operating such generation simply could not compete with natural gas and renewables. Because it could not compete, Solutions announced that it would be exiting the generation business. As a first step in this process Solutions sold 1,572 MW of its generation to LS Power. At the same time, Solutions  announced that it might sell or retire some or all the rest of its plants in the next few years.

But, before completing its exit from the competitive generation business, Solutions thought that it might be special, that it might have a way to by-pass the risks inherent in the PJM market. Solutions asked the FERC to force PJM to change its market rules so that its uneconomic plants would qualify for operation. But the FERC was committed to competitive markets where low cost, efficient generation was encouraged and high cost, inefficient generation was discouraged. The FERC denied Solution’s request for relief.

After being rejected by the FERC Solutions was running out of options. In March, 2018, Solutions filed for Chapter 11 bankruptcy protection. At the same time it announced plans to deactivate its nuclear plants within the next three years. Then, later in 2018, FirstEnergy announced the retirement of 4000 MW of fossil-fueled capacity at Bruce Mansfield, W.H. Sammis and Eastlake.  Solutions, thus, appeared to be moving forward with its plan to exit the competitive power business.

2019 – Ohio Legislation Provides Ratepayer Subsidies for FirstEnergy Solutions

FirstEnergy Solutions Seeks Relief From the Ohio General Assembly

But Solutions did not give up on the idea that it might be able to by-pass the risks of the PJM market. It asked the Ohio General Assembly for help in the form of a ratepayer subsidy. The proposed legislation enabled Solutions to bid its generation into the PJM auctions at prices low enough to qualify for operation. But such a low price would have to be below Solutions’ operating costs. In order to facilitate this uneconomic bidding, the proposed legislation required Ohio ratepayers to provide an additional source of funds for Solutions to cover its costs.

When those of us in the competitive power industry heard about this proposed legislation we were appalled. If the legislation passed, every time that the Solutions’ generation cleared the auction, and was directed to operate, another member of competitive generation industry – one whose generation was less costly and more efficient than FirstEnergy’s – would be bumped offline. The proposed legislation undermined the competitive markets, threatened the investments of all other market participants and risked the jobs of other market participants’ employees. 

The General Assembly Saves FirstEnergy Solutions by Passing House Bill 6

The members of the competitive power industry joined others in opposing Ohio’s proposed legislation. But it was all to no avail. In July, 2019, the legislation was passed as House Bill 6 and signed into law by Governor Mike DeWine.

House Bill 6 accomplished the following:

  • It created a Nuclear Generation Fund into which all Ohio electric ratepayers will pay surcharges totaling $150 million per year for 8 years. Payments will be made out of the Nuclear Generation Fund to Solutions (now named Energy Harbor Generation) for all generation produced by the nuclear plants. This is the subsidy that facilitates Energy Harbor’s bidding of the nuclear energy into the PJM market at below cost. 
  • It reduced the utilities’ Renewable Portfolio Standards requirements from 12.5% of total generation by 2026 to 8.5% in 2026 and eliminated the Renewable Portfolio Standard after 2026 in its entirety.
  • It eliminated Ohio’s energy resource standard (which required improvements in customer efficiency) and eliminated funds for the efficiency programs.

In an article dated, July 27, 2019, Vox called House Bill 6 the “worst energy bill of the 21st century.” But House Bill 6 was the law in Ohio. And it seemed that there was no turning back.

2020 – A Federal Grand Jury Sends Down an Indictment Related to HB 6

The HB 6 Subsidies Enable Solutions to Emerge From Bankruptcy

Prior to passage of HB 6 Solutions had filed for Chapter 11 bankruptcy protection because it was unable to make payments on its existing debt. A debtor can emerge from Chapter 11 if its creditors agree to restructure the debt so that it can make its payments. 

Creditors typically agree to restructure the debt only if the debtor pays some type of partial payment or provides acceptable assurance that it will be able to pay the restructured debt. But Solutions’ only assets – the generating plants – were not selling power into the competitive markets. They were, therefore, pretty much worthless. Solutions could not use its worthless assets to satisfy its creditors.  

That is until the Ohio General Assembly passed HB 6. The ratepayer subsidies in HB 6 transformed the Solutions generating facilities into valuable assets that Solutions could use to resolve its bankruptcy. Solutions’ creditors accepted ownership of Solutions as, at least, partial settlement of their claims. And, in February, 2020, Solutions – then owned by the creditors and renamed Energy Harbor Generation – emerged from Chapter 11 to continue its participation in the competitive power market. 

In mid-July 2020, after the dust had settled, FirstEnergy no longer owned Solutions or any of its generating plants. The former Solutions’ creditors owned Solutions. The new owners had changed Solutions’ name to Energy Harbor Generation. Ohio ratepayers were scheduled to pay into a fund that would be used to subsidize operations of the Energy Harbor Generation plants. The energy efficiency laws applicable to Ohio utilities had been gutted. And competitors in the regional competitive power market were competing with ratepayer subsidized costly and inefficient Energy Harbor Generation plants.

A Federal Grand Jury Brings a Bribery Indictment

Then, on July 20, 2020, a Federal Grand Jury indicted Ohio House Speaker, Larry Householder, four other individuals, and an entity named Generation Now in a racketeering conspiracy. That conspiracy involved $60 million in illegal payments from an unnamed energy company that was used to obtain passage of HB 6.

According to the indictment, a large portion of the $60 million went to support the election of 21 state candidates who, when elected, supported Householder’s election as Speaker of the House and then supported passage of HB 6. Another large portion of the funds went to oppose a ballot initiative aimed at overturning HB 6.

The unnamed energy company referenced in the indictment turned out to be FirstEnergy. FirstEnergy has not been indicted. And there is no suggestion here that the bribery scheme was a FirstEnergy managed strategy. Since being identified as the unnamed energy company, FirstEnergy has claimed to have provided only a quarter of the $60 million. And it has further claimed that, as far as it knew, its payments were for legitimate lobbying services.

All of those who were indicted, are, of course, innocent until proven guilty. And their fates will eventually be decided by the courts. But the fate of HB 6 is now before he Ohio General Assembly.

The Future of HB 6

There is already strong sentiment in Columbus, including Governor DeWine, that HB 6 is tainted and should be repealed. Any such repeal would probably be fairly straightforward. The General Assembly can reinstate the energy efficiency rules that were terminated. And they can terminate the ratepayer charges that were going to be used to subsidize the Energy Harbor plants.

But there is one part of the toothpaste that may not be easy to return to the tube. Solutions’ creditors agreed to take ownership of Solutions as settlement of the Solutions’ debt based on the assumption that the ratepayer subsidies were going to make the plants profitable. Without those subsidies the plants are no longer profitable. They will not have the value assumed by the creditors. Repeal of HB 6 could, therefore, scramble the settlement reached by Solutions and its creditors in bankruptcy court. Expect everyone to now lawyer up. It should be interesting to follow.


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 States Address Climate Change – Cap and Trade

Command and Control or Market Driven Solution

In a prior post we referred to Renewable Portfolio Standard programs as “point of sale” regulations for reducing greenhouse gases. In this post we describe Cap and Trade programs as “point of production” regulations for reducing greenhouse gases.

The two main point of production regulations to reducing greenhouse gases and “command and control” and “market-driven solutions”. In “command and control” the government mandates the quantity of greenhouse gases that may be each generator may produce. In “market-driven solutions”, the government provides incentives for the industry to determine the most cost effective solutions. Cap and Trade is a form of market-driven solution.

Cap and Trade Operation

In a Cap and Trade program the government sets a maximum quantity of greenhouse gases (in tons of carbon) that the industry may produce in any year. This maximum quantity is the “Cap” component of Cap and Trade. The government then issues a quantity of “allowances” equal to the Cap. It may issue the allowances to generators based upon their historic level of greenhouse gas production. Or it may hold an auction in which generators can purchase the allowances. At the end of the year each generator must hold a quantity of allowances equal to its greenhouse gas emissions. Generators that fail to hold an adequate number of allowances must pay a penalty.

Source: Calwatchdog.org

To ensure reduction in greenhouse gases the government will reduce the Cap and the allowances it issues in each succeeding year. Generators that take steps to reduce their greenhouse gas production will reduce the number of allowances that they need. They may also receive additional revenues by selling excess allowances. Generators that do not take steps to reduce their greenhouse gas production will have to purchase additional allowances to avoid the penalty. This opportunity to purchase and sell allowances is the “Trade” component of Cap and Trade.  

By giving generators the option to either purchase allowances or implement efforts to reduce their greenhouse gas production the Cap and Trade programs encourage the industry to take advantage of the most cost effective greenhouse gas reduction solutions. 

Program Successes

Cap and Trade programs generally work as intended. Acid Rain, caused by power plant emissions of nitrogen oxide (NO) and sulfur dioxide (SO2),  was once very harmful to fish and other wildlife. However, a Cap and Trade program established under the Clean Air Act successfully reduced SOemissions from power plants by 50% and substantially eliminated the harm from acid rain. 

And, in 2005, the European Union adopted a Cap and Trade Program aimed at greenhouse gas reduction. That program has a goal of reducing emissions by 21% below 2005 levels by 2020 and by 43% below 2005 levels by 2030. As of 2018, the European Union’s program was considered to be on target, having reduced emissions by 29% below 2005 levels. 

Federal Government Fails to Adopt a Cap and Trade Program

During the 2008 presidential campaign the editorial board of the San Francisco Chronicle asked Barak Obama to describe his response to climate change. Mr. Obama said that he advocated the use of a Cap and Trade program to reduce greenhouse gases.

However, the opponents of such a program pieced together portions of Mr. Obama’s comments and attributed the following quote to him: “If someone wants to build a coal-fired power plant, they can. It’s just that it will bankrupt them.” The Cap and Trade opponents then went on to attribute the following quote to Mr. Obama: “Under my plan. . . electricity rates would necessarily skyrocket.” 

A Google search of “San Francisco Chronicle Obama electricity rates” results in hundreds, if not thousands, of hits to speeches and articles from representatives of the coal industry, coal miners, and industry in general. They all refer to the above quotes and accuse Mr. Obama of seeking to undermine the United States’ economy in general and the coal industry in particular. 

In 2009, after Mr. Obama was elected President, the House of Representatives passed a comprehensive Cap and Trade bill referred to as the American Clean Energy and Security Act of 2009.  But the opposition to Cap and Trade had its effect. The Senate never acted on the House bill and it was never made into law. 

States Begin to Adopt Their Own Programs

In the absence of Federal legislation, the states have begun to implement their own Cap and Trade programs. California was the first state to implement such a program. As of 2017 that program had reduced greenhouse gas emissions in the state by 13%. And California was using revenues obtained from selling the allowances for various energy efficiency and clean air initiatives.

Multiple states participate in the Regional Greenhouse Gas Initiative (RGGI), implemented in 2008. Currently, the states of Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island and Vermont participate. And the program is expanding. New Jersey is scheduled to join in 2020. And Virginia is seeking ways to participate.

Under RGGI, each of the participating states is allocated a share of the annual capped CO2 emissions based on historical emissions. The overall cap and each state’s share of the cap is reduced each year. All of the RGGI states (other than New Hampshire) have committed to adjustments in the cap that will reduce their emissions to the goals of the Paris Climate Accord – i.e. to levels 26% to 28% below 2005 levels by 2025.

The RGGI states conduct annual auctions to distribute allowances used for compliance with RGGI requirements. Through 2014, the RGGI states have used the funds obtained from those auctions to finance $1.37 billion in energy efficiency and clean energy projects.


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 States Address Climate Change – Renewable Portfolio Standards

Failure of the Federal Government to Act on Greenhouse Gas Emissions

On December 12, 2015, the United States and 186 other nations gathered in Paris to sign an historic accord aimed at reducing greenhouse gas emissions.  Under the Paris Accord the United States committed to reducing its greenhouse gas emissions to 26% to 28% below 2005 levels by 2025. Fossil fuel generation accounts for 28% of the greenhouse gas emissions in the United States. Therefore, any effort by the United States to meet its obligations under the Paris Accord will require a plan for increasing use of Renewable Energy. 

In anticipation of the obligations under the Paris Accord, on August 3, 2015, the Environmental Protections Agency issued the Clean Power Plan. The Clean Power Plan directed each state to implement a program for reducing greenhouse gas emissions. It gave the states the flexibility to determine how they intended to comply. If implemented, the Clean Power Plan would have reduced greenhouse gas emissions from power plants by 32%. 

However, after he was elected President, Donald Trump directed the EPA to not implement the Clean Power Plan. He also announced his intention to withdraw the United States from the Paris Accord.

The States Step in to Encourage Renewal Energy Use

In the absence of Federal leadership on greenhouse gas reduction, a number of states adopted their own greenhouse gas reduction programs. Those programs fall into one of the following three categories:

  • Renewable Portfolio Standards (RPS) applicable to electricity sold in the state;
  • Cap-and-trade programs applicable to power plant emissions in the state; and
  • Establishment of a date by which there will be zero greenhouse gas emissions in the state.

This post describes the state RPS programs. Future posts will describe the cap-and-trade programs and the zero emission programs.

RPS Programs – Renewable Energy as a Percentage of Total Electricity Sold

Investor owned electric utilities, municipal utilities, rural electric cooperatives and unregulated competitive suppliers all sell electricity to end-use customers. All of these entities obtain their electricity from somewhere. It might come from their own generation, purchases directly from an independent power producer or purchases from a wholesale power exchange. That electricity is referred to as the seller’s “portfolio” of power supply. 

The electricity in each seller’s portfolio is produced using some type of fuel. Not too long ago, except for small portions produced by nuclear or hydroelectric power, each seller’s entire portfolio would have been produced from fossil fuels like coal, natural gas or oil. There was virtually no electricity produced from renewables like solar or wind power. 

To encourage use of Renewable Energy states that have implemented Renewable Portfolio Standard (RPS) programs. These programs require sellers to include a minimum percentage of Renewable Energy in their electricity portfolios by a date certain. The percentage of renewables and the date certain of their incorporation varies from state to state. But, as examples, Delaware requires 25% renewables by 2025 and California requires 100% renewables by the end of 2045.  

Who is Subject to the RPS Requirements?

The state RPS programs focus on retail electric sales. They require compliance by retail electric sellers. This differs from cap-and-trade programs that focus on power plant emissions and require compliance by electricity generators. 

Iowa implemented the first state RPS program in 1981. Numerous additional states implemented programs in the early 2000s. Currently twenty -nine states and the District of Columbia have adopted mandatory RPS programs. Eight additional states have adopted non-binding RPS goals. The following map depicts all of the binding and non-binding programs:

Investor-owned electric utilities and competitive retail electric suppliers all have to comply with the RPS programs. Depending upon the state, municipal utilities and rural electric cooperatives may also be required to comply. But they are often subject to reduced renewable percentage requirements.

The Sources of Renewable Energy Used to Comply with the RPS programs

Suppliers face significant penalties if they fail to meet the percentage requirements by the date certain. Therefore, they all must implement strategies for obtaining the required Renewable Energy. They will obtain their Renewable Energy from one of the following three sources:

Customer Owned Renewable Energy

Suppliers may obtain a portion of their Renewable Energy by purchasing electricity produced at customer owned renewable facilities. In order to increase the opportunity for these purchases, suppliers may provide incentives to customers who install solar panels on their roofs. These incentives may come in the form of rebates paid to customers for part of the cost of installation. The supplier will then spread the cost of these rebates to its other customers through increases in their electric rates. The state may also include tax credits or direct rebates to customers installing renewables as part its RPS program.

Supplier Owned Renewable Energy

The suppliers may also meet all or part of the requirements by installing their own renewable generation. Alternatively, they may purchase the output from a commercial renewable generation facility located close to their service territory. 

Renewable Energy Credits

Suppliers may also meet their obligation by purchasing Renewable Energy Credits (REC). In states or regions where there is a market for Renewable Energy, qualified renewable generators create one REC for each kWh that they produce. Those RECs have a market value and can be sold independently of the associated kWh.

Electricity sellers that are obligated to meet RPS requirements can purchase the RECs from renewable generators even if they are not located close to the seller’s service territory. From an engineering perspective, there is no way to know whether the kWh produced by the remote renewable generator will actually be delivered to the electricity seller or by the electricity seller to its end-use customers. However, sellers who purchase RECs are deemed to have purchased, and incorporated in their portfolio, the associated renewable energy. 

Success of the RPS Programs

Lawrence Livermore National Laboratory prepares an Annual Status Report summarizing that status of the state RPS programs. The 2018 Annual Report includes the following conclusions:

  • States have generally been meeting their RPS requirement targets.
  • The cost of RPS compliance has been about $4.1 billion – or about 2% of average retail electric bills in RPS states.
  • Roughly half of all growth in non-hydro Renewable Energy since 2000 (from >1% of total electric sales to 11% of total electric sales) is attributable to compliance with state RPS programs.
  • To meet state RPS requirements Renewable Energy will have to grow to about 15% of total electric sales by 2030.
  • Renewable Energy is expected to will grow to about 19% of total electric sales by 2030 through a combination of compliance with RPS requirements and additional Renewable Energy installed in response to market conditions.

The RPS programs appear to be doing what they were intended to do. They are increasing the use of Renewable Energy in the United States.  But these programs will only do so much.  

Without additional state programs or modification to existing programs they will only increase Renewable Energy’s share of total sales to less than 20% of all electricity sold. However, the increased use of Renewable Energy in response to the RPS programs has caused the cost of Renewables to go down. Thus, more Renewables will be installed in the future simply because they are an economic alternative to other forms of generation.   


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. 

PG&E and the California Wildfires

Utilities’ Right to Recover Operating Costs Through Rates

All electric utility regulation relies upon the Regulatory Compact. The Regulatory Compact is a contract between the utilities and the state. The utilities promise to provide reliable service to customers. And the state promises to approve just and reasonable rates for the utility’s services.

Using the state-approved just and reasonable rates utilities are able to recover their cost of providing service, including a reasonable return on its investment. But what happens when a utility incurs extraordinary costs?  Are those costs included in the just and reasonable rates? Or are they excluded from rates and borne by the utility shareholders?

PG&E’s Liability for Fire-Related Damages

That brings us to Pacific Gas & Electric Company (PG&E) and the California wildfires. In recent years PG&E’s equipent has caused California’s most devastating wildfires. The 2018 Camp Fire alone killed 86 people and destroyed 14,000 homes.

Under the usual laws of negligence PG&E would be liable for fire-related damages only if it failed to act reasonably under the circumstances. In other words, PG&E would be liable if it were negligent.  However, in California, the usual laws of negligence do not apply. Under California law, if PG&E’s equipment caused the fires it is liable for all fire-related damages whether or not it was negligent.

PG&E’s Ability to Recover Fire-Related Damages Through Rates

Although California law holds PG&E liable for all of the fire-related damages, it may be able to recoup all or some of those damages through its rates. The California Public Service Commission (CPUC) will decide whether PG&E can recover those damages through rates.

If the CPUC finds that PG&E operated its system prudently PG&E can include the damages in its rates. However, if the CPUC finds that PG&E’s negligence led to the fire-related damages, it will  disallow the recovery of those costs. The CPUC followed this process when it disallowed San Diego Gas & Electric’s request to recoup $379 million of fire-related damages from a 2007 fire.

PG&E, therefore, faces a two-step process. First, PG&E will be liable, under California law, for all 2017 and 2018 fire-related damages caused by its equipment.  Second, PG&E can only recover those costs from ratepayers if the CPUC determines that it operated its system prudently.

PG&E’s Potential Liability From the 2017 and 2018 Fires

PG&E believes that it will be subject to $30 billion in claims for damages arising from the the 2017 and 2018 fires. After its 2007 fire San Diego Gas & Electric (SDG&E) implemented new state of the art fire response procedures. For example, SDG&E now keeps extensive data on every pole in its system; it uses 177 stations to monitor temperature, humidity service and wind speed; it records video from 100 strategically placed cameras in its service territory; it uses satellite data to track where grass is dry; and it shuts down portions of its system when fires are imminent.

Unlike SDG&E, PG&E had not implemented any of those mitigation procedures before the 2017 and 2018 fires. There is, therefore, good reason to suspect that PG&E’s negligence was, at least partly at fault for the fire-related damages. (It should be noted that PG&E is now implementing some of the procedures implemented by San Diego Gas & Electric.)

PG&E’s Possible Breach of the Regulatory Compact

If PG&E cannot recoup all of the fire-related damages through its rates it will have less funds available to pay ongoing operating expenses, to pay down debt and to issue dividends to shareholders. PG&E could ultimately be unable to financially operate its system. If it were unable to operate its system it could be argued that PG&E breached its promise to provide service under the Regulatory Compact and that it should no longer be permitted to operate as a state approved utility.

This would not be the first time that a major utility lost its operating franchise due to a breach of its promise under the Regulatory Compact. In 1998, after many years of poor service and increasing rates, the Long Island Lighting Company (LILCO) lost its franchise to operate. In that case the State of New York created a state agency, the Long Island Power Authority, to purchase LILCO’s facilities and to take responsibility for service in LILCO’s former service territory.

This is the fate for PG&E recently proposed by San Jose’s mayor, Sam Liccardo. In October, 2019, in anticipation of potential wildfires, PG&E shut down portions of its system temporarily cutting off service to hundreds of thousands of customers. Reflecting the frustration of many PG&E customers, Mr. Liccardo suggested that municipalities and counties in the State of California should jointly purchase the PG&E system and turn it into a customer owned utility. If Mr. Liccado’s suggestion gains any traction PG&E’s fate will probably be decided by the CPUC.

PG&E’s Attempt to Stay Solvent

But, for the time being, PG&E has said that its system is not for sale. In addition, it is doing everything that it can to maintain a sound financial footing. In January, 2019, PG&E filed for bankruptcy. Within the bankruptcy process PG&E has already reached financial settlements for fire-related damages with numerous governmental agencies and insurance companies. It has not yet resolved claims with the many individuals who suffered damages. Presumably, PG&E hopes to emerge from bankruptcy as a solvent company able to continue to operate its business.

However, absent some relief from the California State Assembly, PG&E will still be facing considerable challenges after it emerges from bankruptcy. For example, it would still have to face liability for all future fire-related damages caused by its equipment. And the CPUC could still prevent PG&E from recouping those costs if it found that PG&E was negligent. In addition financial institutions are saying that, because of the risks of operating a utility in California, they will have to charge PG&E high interest rates. 

There are many legal, financial and regulatory issues that have to be resolved here. And in 2018 and, again in 2019, the California State Assembly decided to take action. It decided to first focus on the most important issue – ensuring that PG&E and the rest of the utilities in California are financially viable companies capable of taking the actions necessary to reduce damages from wildfires.

SB 901

On September 21, 2018, Governor Brown signed SB 901 into law. SB 901 addresses the above issues as follows:

  • For fires occurring after December 31, 2018 the CPUC will use a new reasonableness standard to determine whether utilities can include fire-related damages in rates. Instead of relying solely upon whether the utility acted reasonably under the circumstances the CPUC will be required to consider the specific wildfire related circumstances. It is believed that this new standard will make it harder for the CPUC to keep fire-related damages out of rates.
  • For fires occurring in 2017 the CPUC will conduct a “financial stress test” for each utility to determine the maximum amount of fire-related damages that they can absorb without incurring financial harm. It is believed that this provision will result in the CPUC allowing fire-related damages in rates which it would have otherwise disallowed under the existing reasonableness standard.

SB 901 does not address fire-related damages from fires that occurred in 2018. It is likely, however, that the State Assembly will revisit this issue in the next session.

SB 901 also imposes new fire mitigation procedures and requirements on the utilities.  

AB 1054

On July 12, 2019, Governor Newsom signed AB 1054 into law. AB 1054 creates a fund of as much as $21 billion that the utilities can use to pay for fire-related damages. The utilities and their ratepayers will initially contribute equally to the fund. The ratepayer portion will be financed through a $2.50 per month surcharge on bills paid over a number of years.

The fund enables the utilities to pay for fire-related damages without waiting for CPUC approval for rate increases. If the CPUC determines that a utility is responsible for fire-related damages it will replenish the fund for the amounts used. If the CPUC determines that a utility is not responsible then ratepayers will replenish the fund through additional or extended surcharges.

Like SB 901, AB 1054 imposes additional fire mitigation procedures and requirements on the utilities.  


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.


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 (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.


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.


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:


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:


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


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.


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.


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.


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.