Electricity regulation in the United States: overview
A Q&A guide to electricity regulation in the United States.
The Q&A gives a high level overview of the domestic electricity market, including domestic electricity companies, electricity generation and renewable energy, transmission, distribution, supply and tax issues. It covers the regulatory structure; foreign ownership; import of electricity; authorisation and operating requirements; trading between generators and suppliers; rates and conditions of sale and proposals for reform.
This Q&A is part of the global guide to energy and natural resources. For a full list of content visit www.practicallaw.com/energy-guide.
The electricity market in the United States has evolved significantly over the past two decades. Vertically integrated utilities have dominated the electricity market for much of the past century. These utilities have traditionally generated, transmitted, and delivered the electricity directly to the end user under the regulation of the public authorities of the particular state in which the utilities operate. In many cases, utilities have operated without competition as regulated monopolies.
The advent of deregulation of the electricity market has changed the traditional market model. Starting in the 1990s, power producers were allowed to compete with utilities in the sale of electricity in the wholesale market, and states began legislating plans to introduce competition into their retail electricity markets. The result has been a significant increase in independent, non-utility power producers that sell their electricity in wholesale markets through interstate transmission networks overseen by regional transmission organisations or independent system operators. In its latest data, the Edison Electric Institute reports that non-utility owned plants accounted for 32.2% of the total electricity generation in the US. Meanwhile, a number of states have made significant progress towards separating the generation, transmission, and sale of electricity as part of instigating competition in the retail electricity markets. However, vertically integrated utilities still control the generation, transmission, and final retail sale of power in many US states.
The trend in the electricity markets at the state level is towards additional competition and the dismantling of traditional vertically integrated utilities. This trend toward greater competition is reflected at the federal level by the disruption of competitive barriers in the wholesale market. For example, in January 2016, the Supreme Court of the United States in Federal Energy Regulatory Commission v Electric Power Supply Association, No 14-840 (25 January 2016) expanded the jurisdictional authority of the Federal Energy Regulatory Commission (FERC), the federal agency charged with regulating the interstate sale of electricity, in a way that introduces competition at the wholesale level by regulating conduct at the retail level. This decision should have a lasting impact on FERC's power to further open competition by blurring the distinction between interstate and intrastate commerce. Many states in the US continue to adhere to the traditional regulated-utility structure for delivering electricity to retail customers.
Another recent trend is the US shale boom's continued impact on energy prices and fuel consumption. Starting around 2008, the production of natural gas from shale grew exponentially. As a result, clean-burning shale gas has in many cases replaced coal as the fuel source of choice for electricity production, a trend driven both by the low cost of shale gas and by environmental pressures on coal-burning plants. Lower-cost electricity resulting from the shale gas boom has helped restore competitive advantages to a number of power-intensive industrial sectors, including manufacturing and petroleum refining. A recent analysis by Harvard Business School and the Boston Consulting Group points out that by 2013, US industrial consumers paid less than half of what their UK and Japanese competitors did for electricity, and 65% less than what their German and Chinese competitors did.
Gas-fired power is likely to remain ascendant. A significant proportion of the US coal-generator fleet is nearing the end of its service life, and anti-carbon regulatory and political actions are amplifying the pressure to retire aging coal capacity. Because of the glut of coal-fired capacity added in the 1970s and early 1980s, the US Energy Information Administration estimates that as much as 40% of US coal-fired generation capacity may need to be replaced within the next 15 years.
The US electricity sector is regulated at the federal, state and local levels. Federal regulation is focused on interstate transmission and wholesale power sales. Interstate transmission of electricity is a form of interstate commerce, which provides a constitutional basis for federal regulation. At the state level, state regulators typically focus on the intrastate generation, transmission and sale of electricity, while local regulators focus on issues such as facility siting and zoning. As an example, state regulators are typically responsible for:
Establishing construction standards for lower-voltage retail distribution facilities.
Setting "quality of service" standards for the sale of retail electricity to end users.
Regulating the prices and terms of electricity service to retail customers.
A range of federal, state and local level entities regulate the US electricity sector. The requisite federal authorities exert profound regulatory influence because much of the country's electrical power infrastructure and markets are considered to be active in interstate commerce. Key federal entities include:
Federal Energy Regulatory Commission (FERC), which regulates interstate electricity sales, wholesale electric rates, and hydroelectric facility licensing, among other energy matters affecting interstate commerce.
US Environmental Protection Agency (EPA), which regulates certain emissions from power-generating facilities.
North American Electric Reliability Corporation (NERC), under FERC oversight, which ensures that the bulk electricity system in North America is reliable, adequate and secure.
Nuclear Regulatory Commission (NRC), which oversees the safety and licensing of nuclear power plants.
US Department of Energy (DOE), which is responsible for promoting energy security as well as scientific and technological innovation.
Other relevant entities, but ones that are typically less directly involved in day-to-day electricity sector regulation, include:
Commodity Futures Trading Commission (CFTC), which regulates certain commodity trades, including power hedges and trade options.
Department of Justice (DOJ) and the Federal Trade Commission (FTC), which enforce anti-trust laws.
Securities and Exchange Commission (SEC), which regulates, among other things, the issuance of corporate securities from energy companies.
Occupational Safety and Health Administration (OSHA), which regulates safety standards for certain power facilities.
See box, The regulatory authorities.
The US electricity generation sector is deep and diverse, with hundreds of utility-scale operators and thousands of generation facilities. Nonetheless, the high capital and regulatory barriers to entry mean a significant portion of power generation rests in relatively few hands. In 2013, the five largest generators accounted for nearly a quarter of utility-scale power production in the US, while the 25 largest operators generated nearly 60% of utility-scale electricity output. The largest investor-owned utilities in the US include:
Energy Future Holdings Corp.
Public Service Enterprise Group Inc.
Among the largest independent power producers are:
NRG Energy Inc.
NextEra Energy Inc.
GDF SUEZ International Power.
In the US market, wholesale power trading typically occurs through bilateral transactions. Beyond that, the structure and operational models of US electricity markets depend on geography. Traditional wholesale electricity markets exist primarily in the Southeast, Southwest, and Northwest, where utilities are responsible for system operations and management and, typically, for providing power to retail consumers. Utilities in these markets are frequently vertically integrated: they own the generation, transmission, and distribution systems used to serve end-user consumers.
In deregulated power markets such as Texas and the Mid-Atlantic region, independent system operators (ISOs) and regional transmission organisations (RTOs) facilitate open access to transmission, and operate the transmission system independently of, and foster competition for electricity generation among, wholesale market participants. ISOs and RTOs use bid-based markets to match sellers and buyers of wholesale electricity. While major sections of the country operate under more traditional market structures, two-thirds of the nation's electricity load is served in RTO regions.
Some of the largest transmission-owning entities in the US are:
Pacific Gas and Electric Co.
Southern California Edison.
Florida Power and Light Co.
About 75% of US electricity sales to final customers are undertaken by private utilities, with the balance sold by municipal utilities and co-operatives. Some of the largest US electricity distributors are:
The US also has a small but growing distributed generation sector, which is primarily driven by the rise of solar power. Key companies engaged in US distributed generation include:
Honeywell International Inc.
Kohler Power Systems.
Foreign entities can own electricity assets in the US. Three foreign corporations have been among the 50 largest power producers in the US since 2013. However, utility-scale electricity generation and transmission assets are generally considered "critical infrastructure". Therefore, any transaction resulting in foreign control over such assets would almost certainly give rise to national security concerns and be subject to review by the Committee on Foreign Investment in the United States.
Import of electricity
The United States is largely self-sufficient in electricity supplies. US Energy Information Administration data for 2014 show that the US imported approximately 53 million megawatt-hours (MWhs) of electricity, primarily from Canadian hydropower producers. To put that number in perspective, the US consumed an overall total of 3.9 billion MWhs in 2014, meaning that imports accounted for only about 1.4% of total electricity use.
Electricity generation and renewable energy
Sources of electricity generation
In 2015, coal and natural gas were the largest fuel sources for US power generation, with each holding a 33% share of the utility-scale generation market, according to the US Energy Information Administration. Two core themes have dominated the past decade in the US generation market.
The first theme is that natural gas is supplanting coal as the main fuel for electricity generation. Between 2005 and 2015, coal's share of the US generation fuel mix plunged from 50% to 33%. Most of the decline happened post-2008. In the first stage of the decline, the shale gas boom unleashed a new wave of supplies that convinced investors a long-term switch away from coal would be sustainable. From 2014 to 2015, anti-carbon policies began to sway generators towards retiring more coal facilities.
The second, slightly less impactful theme is how renewables are eroding fossil fuels' share. Between 2005 and 2015, renewables (led by surging wind power capacity installations) grabbed an additional 4% of market share. This came at the expense of non-gas fossil fuels, primarily coal and petroleum liquids (that is, diesel and crude oil). During the same time, natural gas markets gained 17% of the market share, and non-gas fossil fuels lost more than 20% of the market share.
The US has four primary policy vehicles it uses to support renewable energy development:
Production tax credits (PTCs).
Investment tax credits (ITCs).
Grants made under the American Recovery and Reinvestment Act of 2009 (ARRA).
Renewable portfolio standards (RPSs) and renewable generation capacity goals.
PTCs. PTCs are a production-based incentive and provide a tax credit for the production of electricity from renewable sources and the sale of that electricity to unrelated parties.
ITCs. ITCs incentivise the construction of renewable energy production capacity. An ITC generally allows taxpayers to take a single tax credit against the project's tax basis equal to 30% in its first year, including against the alternative minimum tax with certain limitations. The ITC also allows a taxpayer to elect certain qualified facilities to be characterised as energy property eligible for a 10% or 30% ITC, depending on the technology.
American Recovery and Reinvestment Act of 2009 (ARRA). This Act made some types of projects eligible for grants in lieu of a PTC or an ITC. However, the window for ARRA grants has now largely passed, and moving forward this will not be an important incentive driver of renewable energy projects.
RPSs and renewable generation capacity goals. See below, Renewable energy targets.
Renewable energy targets
By 2025, the US federal government seeks to have 30% of its own electricity consumption come from renewable energy sources. For reference, in fiscal year 2014, federal renewable electricity consumption was 8.76% of its total electricity consumption.
There is currently no federally mandated RPS. 29 individual states, as well as Washington DC, Puerto Rico and the US Virgin Islands, have adopted RPSs. Eight states and two territories have set renewable energy goals establishing a desired level of installed renewable energy generation capacity.
See table, Common forms of renewable energy.
The most significant potential obstacle to further renewable power development in the US is the continued development of abundant, low-cost natural gas resources from shale. Low-cost gas sets the marginal price in the power generation market and makes it tougher for renewable energy producers to achieve price parity. The low price bar set by natural gas helps perpetuate many renewable energy producers' dependence on subsidies and tax incentives that can be threatened by political gridlock in Washington DC.
The Nuclear Regulatory Commission (NRC) currently shows ten reactors in various stages of the permitting process. In addition to those ten units, in February 2016 the NRC approved the construction of two new reactors at the South Texas Project. The project's partners, led by NRG Energy, are currently treating the licence approval as a long-term option. They do not plan to begin construction because of the cost (as much as US$14 billion) and the domination of the US power market by low-cost shale gas.
Authorisation and operating requirements
Regulated utilities and independent power producers can construct generation facilities. Power plant construction is primarily regulated at the state level, generally by state public utility commissions and others with siting authority. Power plants must also comply with local zoning laws. In a significant number of states, prospective utility-scale power plant builders will need to seek a Certificate of Public Convenience and Necessity from state regulators (typically the public utility commission or its equivalent). Parties seeking to construct generation capacity will also need to obtain permits from native, federal, or governmental landowners. In many states, utilities seeking to build power plants can avail themselves of the power of eminent domain (the power to take private land for public good). Some states include participation and comment from citizen/consumer action groups as part of the permitting process. Generation facilities also typically need to obtain air pollution and water permits from the responsible federal and/or state agencies.
Certain types of generation (specifically, hydroelectric and nuclear) are federally regulated. Any hydroelectric project that has the following characteristics must obtain a Federal Energy Regulatory Commission licence:
It is located on a navigable waterway of the US.
It occupies US land.
It uses surplus water from a government-owned dam.
It is located on a water body over which Congress has jurisdiction.
For commercial nuclear power facilities, the Nuclear Regulatory Commission (NRC) regulates design, siting, construction and operation. The NRC also issues:
Early site permits.
Limited work authorisations.
It is also responsible for inspecting nuclear power facility construction sites.
US federal regulations do not currently require CCS. However, stringent new carbon emissions standards in practice mean that new coal-fired generators will need CCS in order to comply. The US Environmental Protection Agency's (EPAs) final rule covering new power plants sets a final emissions standard of 1,305 pounds of carbon dioxide (CO2) per net MWh of electricity generated by fossil fuel-fired electric steam-generating units (with an interim rate of 1,534 lb of CO2/net MWh) and 771 lb/net MWh for stationary combustion turbines (with an interim rate of 832 lb/net MWh). This is less stringent than the 1,100 lb of CO2/net MWh limit originally proposed. But given that the most efficient coal plant without CCS is still likely to emit around 1,700 lb of CO2/net MWh, adopting CCS will likely be necessary.
As of February 2016, the final EPA rule has been stayed by order of the US Supreme Court and awaits disposition of the industry's petitions for review in the Court of Appeals for the District of Columbia. While the ultimate limits remain in legal limbo, EPA's actions so far have communicated clear risk signals to prospective generation facility operators and investors. In response, these parties are moving more strongly toward natural gas and other generation modes less affected by the growing anti-coal regulatory campaign, a trend that we expect will continue even if the pending court decisions favour the industry's side of the case.
Each state in the US maintains varying ongoing requirements for generation facilities operating within the particular state's jurisdiction. At a regional level, generation facilities must meet the Federal Energy Regulatory Commission (FERC) standards to participate in wholesale electricity markets, including reliability standards. Certain generation plants fall within FERC's jurisdiction by virtue of their fuel type, including hydropower plants. Meanwhile, nuclear plants are regulated by the Nuclear Regulatory Commission, which periodically renews nuclear plants' licences through a process that includes:
A technical review.
An integrated plant assessment.
An environmental study.
Power plant operators must also adhere to the work practices and worker training requirements set out in the Occupational Safety and Health Administration Electric Power Generation, Transmission, and Distribution Standard, and they must also comply with any local zoning regulations or ordinances.
The Federal Energy Regulatory Commission (FERC) has jurisdiction over the interconnection of generators with transmission lines. Three key FERC orders provide rules governing interconnection between generators and transmission lines that fall under its jurisdiction:
Order No 2003 provides rules for large generators (over 20 MW).
Order No 2006 provides rules for small generators (under 20 MW).
Order No 661 provides special interconnection rules for large wind generators.
The ultimate objective of these orders is to help ensure that all generating facilities that sell electricity for resale into interstate commerce can obtain interconnection services on comparable terms.
FERC requires public utilities that own, control or operate facilities for transmitting electricity in interstate commerce to have pro forma Large Generator Interconnection Procedures on file with FERC as part of their transmission tariff (Order No 2003). This rule aims to:
Reduce interconnection time and cost.
Help preserve reliability.
Increase energy supply.
Lower wholesale prices for the nation's customers by increasing the number and variety of independent generators that can compete in the wholesale electricity markets.
The rule also requires public utilities that offer transmission services to offer non-discriminatory, standardised interconnection service. To help clarify the requirements, FERC makes available a Large Generator Interconnection Agreement, which:
Establishes the legal rights and obligations of each party.
Identifies necessary system upgrades and facilities.
Addresses cost responsibility.
Describes the dispute resolution process.
There is a similar, but more streamlined, set of procedures established in FERC Order No 2006 to govern the interconnection of generators smaller than 20 MW. Ultimately, when FERC examines interconnection requests, it most closely examines the impacts on system reliability. If an interconnection causes local grids to need upgrading or improvement, the interconnecting generator typically pays for those. The costs of broader regional upgrades are generally allocated in a manner approximately commensurate with the benefits each party receives.
Authorisation and operating requirements
Parties seeking to build transmission lines must generally file applications with multiple state agencies and local governments. If a state has siting authority, then the project sponsor must file an application with the state. Each state has its own procedures and processes for granting approval to power line projects, and they also vary as to the extent to which they allow developers to use powers of eminent domain. State environmental regulators can also become involved in siting to address environmental issues, and state health officials can review a prospective power line project in a populated area to assess electromagnetic fields that would be produced by currents in the line and their potential effects on people nearby.
Federal transmission infrastructure siting power for interstate projects is currently split between the US Department of Energy (DOE) and the Federal Energy Regulatory Commission (FERC). There is an ongoing push in the US Senate to amend the Federal Power Act (2012) to improve the siting of interstate electricity transmission facilities. FERC can use its siting authority only if the proposed line is within a corridor designated by the DOE as an area of transmission congestion that adversely affects consumers.
New transmission projects often face stiff obstacles, including:
"Not in my backyard" opposition.
The National Environmental Policy Act requirement that agencies such as the US Environmental Protection Agency or FERC either prepare an Environmental Assessment and issue a "finding of no significant impact", or prepare an Environmental Impact Statement evaluating the relevant environmental effects of a proposed federal project.
The Federal Energy Regulatory Commission (FERC) seeks to promote competition in the wholesale power markets and maximise the availability of lower-cost, reliable power supplies to US electricity consumers. All public utilities that own, control or operate transmission infrastructure used to transport power in interstate commerce are required to file open access, non-discriminatory transmission tariffs. These outline baseline terms and conditions of non-discriminatory service.
In regions with independent system operators (ISOs) and regional transmission organisations (RTOs), utilities that own transmission lines delegate day-to-day operating and regional planning responsibilities to the RTO. RTOs and ISOs seek to ensure that all transmission owners and transmission customers have fair and open access to transmission services. They also:
Detail the rights and responsibilities of transmission owners and transmission customers, as well as the procedures they must follow and the fees transmission customers must pay to access the transmission system.
Set out the transmission system planning process for the region.
Set out the cost recovery and allocation mechanisms for transmission and ancillary services in the region.
FERC has approved seven organisations as RTOs or ISOs. These manage approximately 60% of US electricity demand and are all required to comply with FERC-approved mandatory reliability standards established by the North American Electric Reliability Corporation (NERC). Once an ISO or RTO is registered with NERC, it must comply with standards for reliability and performance, as well as provide real-time monitoring and ongoing reporting.
The Federal Energy Regulatory Commission (FERC) regulates the pricing of interstate and wholesale transmission services. Transmission rates can take one of several forms, including:
Postage stamp pricing (one rate regardless of distance).
Licence plate pricing (a price within a specified zone).
Point-to-point distance-sensitive pricing.
Transmission pricing can also be "pancaked", which means that as power moves over numerous lines through several transmission owners, each owner gets paid its share for the use of its facilities.
Transmission regulation is governed by three important FERC decisions:
Order No 888.
Order No 889.
Order No 2000.
Order No 888 requires utilities to separate their transmission and generation businesses in order to provide open access to transmission rates and avoid discriminatory or preferential pricing. Order No 889 created a system by which available capacity on transmission lines was posted, so that any party connected to the transmission system could track availability. Order No 2000 encourages utilities to form regional transmission organisations (RTOs), which will have the duty to develop transmission plans and pricing structures for a particular region to promote competition in wholesale markets.
In order to boost investment in transmission networks, the Energy Policy Act of 2005 tasked FERC with developing incentive-based rates for transmission services in interstate markets. That rule implemented this new statutory directive through the following incentive-based rate treatments:
Incentive rates of return on equity for new investment by public utilities (both traditional utilities and stand-alone transmission companies, or transcos).
Full recovery of prudently incurred construction work in progress.
Full recovery of prudently incurred pre-operations costs.
Full recovery of prudently incurred costs of abandoned facilities.
Use of hypothetical capital structures.
Accumulated deferred income taxes for transcos.
Adjustments to book value for transco sales/purchases.
Deferred cost recovery for utilities with retail rate freezes.
A higher rate of return on equity for utilities that join and/or continue to be members of transmission organisations, such as (but not limited to) RTOs and independent system operators.
Authorisation and operating requirements
While historically electricity distribution was largely regulated at the state and local levels, today authorisation requirements depend on whether distribution systems will travel across more than one state or be wholly intrastate systems.
If a distribution system is within a state, the state's public utility commission (PUC) will give authorisation for construction of a distribution service. While each state's authorisation process is different, PUCs generally look at environmental, economic, and public health concerns when determining whether the construction of a particular distribution system will be authorised. In some states, there is a central siting board or commission where a utility can obtain all authorisations for construction of a distribution system in one place. In other states, a utility or developer must obtain each permit separately from the necessary state and local agencies. If the utility is regulated, it must obtain a certificate of public convenience and necessity from the state PUC to construct the distribution system.
If a distribution system is constructed across state borders, the Federal Energy Regulatory Commission's (FERC) regulations will apply to the construction of the distribution system. Unlike state-regulated distribution systems, a utility or developer need not obtain a federal certificate of public convenience or necessity from FERC under Part II of the Federal Power Act (2012).
Utilities have varying obligations in operating electricity distribution systems depending on the state at issue. Generally, state public utility commissions (PUCs) authorise the operation of electricity distribution systems, and require that utilities maintain safe and reliable distribution systems in serving customers within their service territories. As an example, such requirements can obligate a utility to update electricity poles and wires as needed, and promptly respond to and fix electricity outages. If a state has adopted retail competition in its electricity market, utilities can also be required to make their distribution systems available to competitive suppliers to allow for the delivery of electricity to customers.
State agencies like public utility commissions (PUCs) generally determine the rates and conditions for the intrastate distribution of electricity. Distribution services are considered a natural monopoly. Since competition does not exist in a monopoly, state PUCs use a cost-of-service analysis to determine the price of electricity distribution. Prices are set so that the utility can recover its costs plus a predetermined profit level. PUCs set and review utility rates through a process called a "rate case". PUCs inspect the historical and projected costs of a utility to determine a distribution rate. Utilities can change rate designs and levels only in a rate case. Some states require utilities to submit to rate cases on a periodic basis set by the PUC, but rate cases are frequently the result of a request for a rate review by an intervener.
On an interstate level, the Federal Energy Regulatory Commission (FERC) regulates the charges and conditions for the distribution of electricity through a rule-making process. The charges and conditions are then implemented at the interstate (regional) level through FERC and/or the regional transmission organisations working under FERC.
Authorisation and operating requirements
The Federal Energy Regulatory Commission has regulatory authority over the sale of wholesale electricity in interstate commerce. Intrastate retail sales of electricity to end consumers are regulated at the state level through public utility commissions (PUCs). The authorisation and ongoing requirements for any entity that supplies electricity to end consumers vary widely from state to state. In order to determine what the authorisations are for a particular state, a utility or interested developer should look to the regulations of the particular state at issue.
Trading between generators and suppliers
Electricity trading occurs in two ways:
Through regional transmission organisations (RTO) markets.
Through bilateral agreements.
RTOs co-ordinate the buying, selling and delivery of wholesale electricity through the electricity market. Much like a stock exchange, the market participants establish the price in the electricity market based on supply and demand through a competitive bidding process. The energy market consists of the day-ahead market and the real-time market. The day-ahead market calculates hourly prices for the following day based on generation offers, demand bids, and bilateral transactions. The real-time market calculates current locational prices in five-minute intervals based on actual grid operating conditions. Sellers that sell into the day-ahead and real-time markets do so subject to the specific RTO market rules approved by the Federal Energy Regulatory Commission (FERC). A seller in a day-ahead or real-time market must:
Obtain authorisation from FERC to sell at market-based rates.
Follow the additional rules of each RTO tariff, which it sells under.
In bilateral agreements, buyers and sellers negotiate with each other to reach a contractual agreement to sell or buy electricity, rights to generating capacity, or related products under mutually agreeable terms for a specific period of time. The benefit of bilateral markets is that each party can determine the terms by which it will buy or sell electricity without FERC or RTO oversight.
Electricity price and conditions of sale
State public utility commissions (PUCs) regulate the price and conditions of sale of electricity to consumers by regulated utilities. The PUC generally establishes a rate that utilities can charge their customers based on a cost-of-service analysis. Rates consist of a number of components, including:
Customer service charges.
Some states also have retail competition or retail choice, in which customers are allowed to choose between their current utility provider and competitive suppliers of retail electricity. In these cases, state PUCs may not regulate the price of electricity, but they generally continue to regulate other conditions of sale, such as contract terms and marketing prices by the competitive suppliers. In addition, competitive suppliers must generally seek approval from the state PUC before entering a new market.
Section 205 of the Federal Power Act (2012) grants the Federal Energy Regulatory Commission (FERC) exclusive regulatory authority over the sale of wholesale electricity to ensure that rates are just and reasonable (which requires that the rates be cost- and market-justified), and not unduly discriminatory or preferential (which requires that similarly situated parties be treated similarly).
Traditionally, FERC used a cost-of-service inquiry to review wholesale electricity rates. Cost-based rates are used if a supplier does not seek market-based authority or is unable to show that it cannot exercise market power. Cost-based rates, which are typically listed in a published tariff, allow a supplier to recover its costs of providing service and a fair return on capital.
Today, FERC regulates wholesale electricity rates largely through market-based rates. FERC grants market-based rate authorisation to sellers that show they and their affiliates either:
Lack market power.
Have adequately mitigated horizontal and vertical market power.
FERC must approve a jurisdictional entity's generic market tariff. Once FERC has done so, the entity can negotiate with other parties in the marketplace to determine a specific rate for wholesale electricity without having to seek any further approval from FERC. In competitive markets, prices generally reflect the factors driving supply and demand.
The main tax issue in the electricity sector currently is the use of incentive-based tax credits to encourage renewable energy sources. The Energy Policy Act of 1992 created incentives for the construction of renewable energy. Tax credits are the primary driver behind the development of renewable energy projects, and without these credits, renewable energy projects largely might not make financial sense for investors and utilities. The two primary tax credits available for renewable energy are:
Investment tax credits (ITCs).
Production tax credits (PTCs).
The ITC is a tax credit for qualified taxpaying owners based on their capital investments in solar energy projects. In December 2015, the government extended the ITC until 31 December 2019 for solar energy. ITCs are equal to 30% of the basis that is invested in eligible property that is placed in service. The basis of the energy property is reduced by 50% of the ITC. The ITC is subject to recapture if the project is disposed of or ceases to be an energy property in the first five years.
PTCs are tax credits based on the electrical output (measured by an inflation-adjusted amount multiplied by the kilowatt-hour of electricity produced) of renewable energy facilities connected to the grid and sold to an unrelated party. PTCs are available for a ten-year period beginning when the facility was originally placed into service. In December 2015, the government extended the expiration date for PTCs to:
31 December 2019 (for wind facilities).
31 December 2016 (for other eligible renewable energy technologies).
The amounts of PTCs are reduced by grants, tax-exempt bonds, subsidised financing, and other credits received with respect to each project.
Currently, there are no major reform proposals for the regulation of the electricity sector. But the line between the areas of the electricity sector regulated by the Federal Energy Regulatory Commission (FERC) and the areas that have traditionally been regulated by states is becoming blurred. As disagreement continues over whether FERC or states have the power to regulate the various divisions of the electricity sector (especially retail markets), we may see some reform proposals in the near future that will attempt to clarify the regulatory roles of federal and state regulators.
While there are no reform proposals currently that would alter the regulation of the electricity sector, the electricity sector is undergoing a sea change across the country due to the deregulation of the sector. Changes that should be noted include:
The expansive growth of the renewable energy sector.
The continued shift from coal to natural gas.
States' efforts to separate the generation, transmission and sale of electricity.
The regulatory authorities
Federal Energy Regulatory Commission (FERC)
Address. 888 First Street, NE
Washington, DC 20426
T +1 202 502 6088
F +1 202 208 2106
Main responsibilities. Regulates interstate electricity sales, wholesale electricity rates, and hydroelectric facility licensing, among other energy matters affecting interstate commerce.
US Environmental Protection Agency (EPA)
Address. 1200 Pennsylvania Avenue, NW
Washington, DC 20460
T +1 202 272 0167
F +1 202 501 1450
Main responsibilities. Regulates certain emissions from power-generating facilities.
North American Electric Reliability Corporation (NERC)
Address. 3353 Peachtree Road, NE, Suite 600, North Tower
Atlanta, GA 30326
T +1 404 446 2560
Main responsibilities. Operates under FERC oversight and is responsible for ensuring that the bulk electricity system in North America is reliable, adequate and secure.
Nuclear Regulatory Commission (NRC)
Address. 11555 Rockville Pike
Rockville, MD 20852
T +1 301 415 7000
F +1 301 415 1672
Main responsibilities. Oversees the safety and licensing of nuclear power plants.
US Department of Energy (DOE)
Address. 1000 Independence Avenue, SW
Washington, DC 20585
T +1 202 586 5000
F +1 202 586 4403
Main responsibilities. Promotes energy security as well as scientific and technological innovation.
Description. Comprehensive government data site that addresses all aspects of energy production and consumption in the US.
Description. Handbook of energy market basics drafted by FERC.
Description. A comprehensive source of information on state, federal, local and utility incentives and policies that support renewable energy and energy efficiency.
Description. Source of intensive research and analysis on the functions, operation, and government regulation of global energy markets.
Description. Comprehensive data on tax credits, rebates, and savings available in each state.
Description. List of federal statutes that FERC must comply with along with the FPA, which gives FERC its legal authority.
Martin T Booher, Partner
Admitted to practice law:
US District Court, District of Connecticut.
US District Court, Eastern District of Arkansas.
US District Court, Western District of Arkansas.
Areas of practice. Environmental; project development and finance; shale; eminent domain; energy.
JD, Pace University School of Law, 1998, cum laude, Environmental Law Certificate, Dean's List.
BA, Bucknell University, 1995, cum laude, Dean's List.
Advises electric utilities concerning the disclosure of climate change and EHS risks in filings with the SEC.
Assists clients in the analysis, preparation, and negotiation of power purchase and tolling agreements between electricity generators and off-takers.
American Bar Association.
Environment, Energy, and Resources Section: Committee on Air Quality, vice chair.
Ohio Gas Association.
Ohio Oil & Gas Association.
Shale Media Group.
Pratt's Energy Law Report.
David F Proaño, Partner
Admitted to practice law:
US Court of Appeals, Sixth Circuit.
US District Court, Southern District of Ohio.
US District Court, Northern District of Ohio.
Areas of practice. Complex commercial litigation; energy.
JD, Harvard Law School, 2004; senior editor, Harvard Environmental Law Review.
BS, Calvin College, 1998.
Successfully represented a steel manufacturer before the Public Utilities Commission of Ohio involving a demand by an electricity supplier for millions of dollars in security on a large electricity supply contract.
Successfully defended a Fortune 500 company in an appeal involving environmental clean-up claims and novel issues of state environmental laws.
Regulatory counsel for a competitive retail electricity supplier in Ohio.
Languages. English, Spanish (conversant)
American Bar Association.
Ohio State Bar Association.
Cleveland Metropolitan Bar Association.
Kendall Kash, Associate
Professional qualifications. Admitted to practice law in Ohio.
Area of practice. Energy.
JD, Case Western Reserve University School of Law, 2015, magna cum laude, Order of the Coif.
BA, International Studies, University of Illinois, 2009.
Advised client on Tier II reporting requirements under the Emergency Planning and Community Right-to-Know Act.
Assisted client in submitting voluntary disclosures of potential environmental violations under EPA's self-policing audit policy and state audit privilege and immunity laws.
American Bar Association.
Ohio State Bar Association.
Shale Media Group.
Pratt's Energy Law Report.