Regulation of electricity utilities – power generation

Authorisation to construct and operate generation facilities

What authorisations are required to construct and operate generation facilities?

The siting and construction of electric generation, transmission and distribution facilities has historically been a state and local process, although EPAct 2005 altered this traditional arrangement by vesting limited transmission siting authority with FERC in certain cases. In making siting decisions, state public utility commissions (PUCs) consider environmental, public health and economic factors. The PUCs exercise their authority in conjunction with state environmental agencies or local zoning boards. A few states have a siting board or commission that provides a single forum where an electric utility or independent developer can obtain all necessary authorisations to construct electric facilities. Other states have not consolidated the siting process, and electric utilities or independent developers in those states are required to obtain the necessary permits separately from each of the relevant state and local agencies. State and local permits required for the construction of electric generation facilities include air permits and water use or discharge permits from the state environmental commission, and zoning and building permits from local commissions.

Regulated utilities are required to obtain a certificate of public convenience and necessity from the relevant PUC for the construction of generation, transmission and distribution facilities that will be subject to cost-base rate regulation. Except in limited circumstances where the relevant state commission refuses to act on an application for a year, or does not have jurisdiction to act (as in the case of certain federally designated National Transmission Corridors), no federal certificate of public convenience or necessity is available from FERC for the siting and construction of electric generation, transmission or distribution facilities under part II of the FPA.

A FERC licence must be obtained under part I of the FPA for the construction of hydroelectric facilities on navigable waters. Construction affecting federal lands may also require authorisation from agencies such as the Bureau of Land Management, the US Forest Service or the National Park Service. The US Army Corps of Engineers reviews projects affecting wetlands or navigable waters. Nuclear facilities must be licensed by the US Nuclear Regulatory Commission (NRC). The Bureau of Ocean Energy Management and the Bureau of Safety and Environmental Enforcement within the Department of the Interior are responsible for offshore oil and gas lease sales and offshore renewable energy development.

Grid connection policies

What are the policies with respect to connection of generation to the transmission grid?

FERC-jurisdictional transmission providers are required to provide interconnection service under the terms of an OATT. Generators have the right to request interconnection services separately from transmission services.

In response to complaints by generators that interconnection procedures were being used by some transmission providers in a discriminatory manner, FERC implemented rules to standardise agreements and procedures for generators and required FERC-jurisdictional transmission providers to interconnect generators to the grid in a non-discriminatory manner. Under the standard interconnection procedures, generators are required to pay the full cost of any interconnection facilities up front (from the generator to the point of interconnection) and network transmission facilities (beyond the point of interconnection) necessary to connect the generator with the transmission grid. The generator is reimbursed for the cost of any network transmission facilities through credits for future transmission service on the grid. ISOs and RTOs have the flexibility to propose changes to the standard interconnection agreement and procedures, as well as to the procedures for recovering interconnection costs. For example, ISOs and RTOs may seek authorisation to allocate the costs of network upgrades to the generator requesting the upgrades (in exchange for granting capacity rights on the transmission system). FERC does not regulate local distribution facilities, but has authority to regulate the rates, terms and conditions of any wholesale sales transaction using such a facility. See question 11 for further discussion.

To encourage development of new generation, FERC issued Order No. 807, easing the requirement for certain generator owners and operators to have an OATT on file with FERC for public utilities who are subject to those regulations solely because they own or operate Interconnection Customer Interconnection Facilities (ICIF), namely those that own generator tie lines. Previously, an ICIF owner must have either had on file an OATT or received a case-by-case waiver of the OATT requirement, and also was obligated to provide interconnection service to other generators that sought to interconnect to the grid using its ICIF. To ease the regulatory burden on new generation developers, the new rule grants a blanket waiver of all OATT and other open access requirements to any public utility that is subject to those requirements solely because it owns, controls, or operates an ICIF, including entities that do not sell electricity. In addition, the rule provides a ‘safe harbour’ period for five years in which there would be a rebuttable presumption that the ICIF owner has definitive plans to use its capacity and therefore are not required to provide interconnection service to other generators seeking to interconnect generation in the same location during the safe harbour period.

Alternative energy sources

Does government policy or legislation encourage power generation based on alternative energy sources such as renewable energies or combined heat and power?

Yes. Legislation passed and signed into law by the president in 2009, the American Recovery and Reinvestment Act of 2009 (Recovery Act), contains provisions for direct spending, tax credits and loan guarantee programmes designed to promote development of renewable energy projects. The Recovery Act extended the production tax credit (PTC) on renewable energy systems, while also offering expansions on and alternatives for PTCs (http://energy.gov/savings/renewable-electricity-production-tax-credit-ptc). The US Congress continued the PTC in the Bipartisan Budget Act of 2018 despite speculation that Congress was considering reducing or eliminating it. The PTC is available for most renewable energy systems for facilities that have commenced construction before 1 January 2018. In December 2015, the relevant laws were amended to further extend the PTC for wind facilities to include those for which construction begins before 1 January 2020, but this extension was accompanied by a phase-out of the PTC for wind facilities over a four-year period. Where construction of a wind facility begins prior to 1 January 2017, the full PTC is available. For wind facilities where construction is commenced after 2016 and before 2020, the PTC available is reduced by 20 per cent for facilities with construction beginning in 2017, by 40 per cent where construction is commenced in 2018, and by 60 per cent for facilities begun in 2019.

Solar facilities are eligible for an investment tax credit (ITC) in which, as an alternative to the PTC, a project developer may elect a grant equal to a percentage of the facility’s tax basis, so long as the facility is depreciable and amortisable and placed into service before 1 January 2022. The ITC applies in the year in which the qualifying property is placed in service and is a credit equal to a percentage of the taxpayer’s tax basis in certain qualifying investments. For solar facilities placed in service by 2020, the credit is 26 per cent, and 22 per cent for facilities placed in service by 2021. A solar facility for which construction commences before 1 January 2022 but which is placed in service after 31 December 2021 is eligible for only a 10 per cent ITC.

The DoE Office of Energy Efficiency and Renewable Energy (EERE) is the focal point for several alternative energy programmes, including the biomass programme, the geothermal technologies programme, the solar energies technologies programme, the hydrogen, fuel cells and infrastructure technologies programme, and the wind and hydropower technologies programme (www.eere.energy.gov). The EERE provides a variety of forms of financial assistance for the research and development of renewable energy, including grants, laboratory subcontracts, and cooperative research and development agreements (www1.eere.energy.gov/financing/types_assistance.html). Moreover, as of August 2018, 29 states plus the District of Columbia and three US Territories have adopted renewable portfolio standards that require electricity providers to obtain a minimum percentage of their power from renewable energy resources by a certain date (http://www.ncsl.org/research/energy/renewable-portfolio-standards.aspx), and eight others (and one US territory) have set voluntary goals for adopting renewable energy resources (http://ncsolarcen-prod.s3.amazonaws.com/wp-content/uploads/2014/11/Renewable-Portfolio-Standards.pdf). As of March 2015, 20 of these states include combined heat and power (CHP) and/or waste heat recovery as an eligible resource (https://www.epa.gov/sites/production/files/2015-07/documents/portfolio_standards_and_the_promotion_of_combined_heat_and_power.pdf).

Cogeneration and small power production purchase and sale requirements

EPAct 2005 amended the mandatory purchase and sale requirements of the Public Utility Regulatory Policies Act (PURPA). Historically, electric utilities were obligated to purchase or sell electric energy from or to a facility that is an existing qualifying cogeneration or small power production facility (QF). However, if the QF is selling in a market that meets certain criteria established by FERC, that purchase obligation may be terminated. In 2006 FERC issued Order No. 688, which permits the termination of the requirement that an electric utility enter into new contracts to sell energy to or purchase energy from a QF after the electric utility files for such relief from FERC, and FERC makes appropriate findings. Several utilities have successfully pursued relief under Order No. 688. These changes do not affect pre-existing contracts or obligations.

Climate change

What impact will government policy on climate change have on the types of resources that are used to meet electricity demand and on the cost and amount of power that is consumed?

Federal and state climate change policies promoting carbon-free energy sources are more likely to have an impact on the types of resource used to meet US electricity demand in the medium- or long-term time frame than in the short term. The US electric industry’s reliance on fossil fuels (particularly coal) to meet rising energy demands is driven primarily by cost considerations: coal, for many years, has been a cheap and plentiful domestic fuel source. That dynamic is shifting, however, as the influx of low variable-cost renewable projects and the continued development of shale gas resources (and the resultant low natural gas prices) have narrowed the energy cost advantages of coal generation, particularly for older, less efficient coal units. Although recent federal and state legislative initiatives have provided down payments toward the creation of cost-competitive renewable energy technologies, the large-scale deployment of these technologies is still hampered by variability of resources such as wind, the need for additional backbone transmission capacity between regions, and the lack of storage capacity.

Other proposed state and federal legislation (for example, cap-and-trade schemes) and foreign policy initiatives could impose additional costs on electricity generators using carbon-rich fossil fuels. In general, legislative proposals and environmental regulations are likely to impose greater costs on the energy that is consumed. State or federal governments could subsidise renewable energy and carbon mitigation initiatives by surcharges on electricity generation or consumption. Compliance costs incurred by utilities arising from state or international cap-and-trade legislation, federal regulations, or state regulation of vehicular carbon emissions would be passed on through every transaction involving electricity.

The Environmental Protection Agency (EPA) is the chief US agency tasked with issuing regulations under the Clean Air Act (CAA) regarding pollutants and carbon dioxide emissions from power generation sources. For instance, new and existing coal-fired plants may be incentivised or required to have carbon capture and sequestration (CCS) capabilities. In 2011 the EPA issued the Cross-State Air Pollution Rule under the Clean Air Act that requires coal companies in 28 states to reduce emissions of sulphur dioxide and nitrogen dioxide by 73 per cent and 54 per cent, respectively, from 2005 levels by 2014. The rule was controversial, with many in the coal industry claiming that it will be cost-prohibitive to obtain and install the CCS technology necessary to meet the standard. As a result, the coal industry warns that coal generating facilities will be forced to prematurely shut down. In April 2014, the US Supreme Court upheld the EPA rule, affirming EPA’s authority to regulate existing power plants for greenhouse gases so long as they are being regulated for other pollutants as well.

The issue of how to properly account for compliance costs of pollution reduction was at the heart of a 2015 US Supreme Court case. There, the US Supreme Court remanded an EPA rule setting limits on mercury and other toxic pollutants from power plants, ruling that the EPA violated the CAA by failing to consider costs when deciding whether to set those emissions limits in the first place, although the EPA did eventually undertake a cost-benefit analysis when subsequently deciding how to regulate. As the EPA continues to issue new regulations related to pollution and climate change, whether and how to account for compliance costs will remain a key issue.

Perhaps the largest and most impactful regulatory initiative pertaining to climate change concerns the regulation of carbon dioxide emission limits from existing power plants. In June 2013, the US president ordered the EPA to create the first ever carbon emissions limit for existing power plants, stating that the United States should lead the world in a ‘coordinated assault’ on climate change (www.whitehouse.gov/the-press-office/2013/06/25/remarks-president-climate-change). In August 2015, pursuant to the president’s directive, the EPA promulgated its final regulations under part 111(d) of the CAA, which is known as the Clean Power Plan (CPP). In general, the CPP establishes broad carbon-dioxide emission targets for coal- and natural-gas fired power plants intended to cut CO2 emissions by 32 per cent by 2030, leaving the states (excluding Vermont, Hawaii, Alaska, and the District of Columbia) to choose from a variety of methods - such as renewable energies, efficiency improvements, or participating in an emission credit trading programme - to develop a plan to meet individual targets.

However, in February 2016, the US Supreme Court stayed implementation of the CPP while court challenges to the plan were pending before the US Court of Appeals for the DC Circuit. Then, in March 2017, President Trump issued an Executive Order requiring the EPA to review the CPP so as to consider whether to ‘suspend, revise, or rescind’ it. Importantly, however, if the EPA rescinds the CPP, the EPA has not proposed revoking its 2009 ‘endangerment finding’ - a determination that greenhouse gases, including carbon dioxide, are a threat to human health - and as such, the EPA is required to regulate greenhouse gasses pursuant to the statutory directive of the CAA.

As such, and in accordance with the March 2017 Executive Order, in August 2018, the EPA proposed a new rule that would rescind the CPP and instead, replace it with a new set of regulations, known as the Affordable Clean Energy (ACE) rule. The proposed ACE rule establishes guidelines for states to develop plans and programmes regarding greenhouse gas emissions from existing coal-fired power plants. According to EPA, approximately 600 coal-fired electric generating units at 300 facilities in the US would be subject to the proposed ACE rule. The legal framework of the proposed ACE rule includes only existing generation sources and therefore falls under Section 111 of the Clean Air Act. The proposed ACE rule empowers states to craft plans establishing standards of performance for existing sources. Upon evaluation of those submittals, EPA ultimately determines the best system of emission reduction (BSER). EPA is pre-emptively designating a range of candidate technologies that may be used to demonstrate the BSER for coal-fired power plants. In the proposed ACE rule, EPA defines the BSER as a technological solution to improve the heat rate efficiency of individual coal-fired units, a distinction from the broader, portfolio-level mandate of the CPP. Notably, the timelines for states to comply with the ACE rule to develop their plans for EPA and, if necessary, for a federal plan to be implemented if a state plan was not submitted or rejected have all been extended significantly as compared to the CPP. States may now take up to three years to draft and submit their respective plans (versus nine months under the CPP), and EPA would then have up to one year to review and act upon those submittals (versus four months in the CPP). It is expected that any final rule issued by the EPA would immediately be challenged in court. Moreover, with another presidential election looming in 2020, it is possible that a new presidential administration could decide to change course yet again.

Nonetheless, even without the CPP, and even if its successor the ACW rule goes into effect, the development of renewable resources is expected to continue. This is due in large part to state initiatives aimed at incentivising development of renewable resources and technological developments making the use of renewable resources more and more economical. However, it should be noted that the increased integration of renewable resources into the electric grid raises issues around grid reliability. In general, FERC and NERC are tasked with maintaining reliability for the Bulk Electric System. As generating capacity from coal-fired and other traditional baseload resources decreases, it will be important to develop suitable replacement generation and transmission resources that are sufficient to maintain capacity to meet electricity demand, particularly during times of peak usage in order to avoid reliability problems. Moreover, as most renewable generation resources, such as wind and solar sources, are in remote locations, additional transmission infrastructure must be constructed. Energy storage resources may also be needed to ensure reliability, such that sufficient energy can be saved and then deployed during times of peak usage given that generation from variable resources inherently fluctuate.

In addition, a number of utilities have closed or announced plans to shut down certain, mostly older, less efficient, coal power plants. Meanwhile, the US coal reversed course from a four-year trend of declining levels, with exports increasing in 2017 to 97.0 million short tons, which is 61 per cent higher than 2016 (https://www.eia.gov/todayinenergy/detail.php?id=35852). In 2017, exports to markets in Asia more than doubled (particularly owing to steam coal, used for electricity generation), comprising a bulk of the increase from 2016 and the broader downward trend.

Storage

Does the regulatory framework support electricity storage including research and development of storage solutions?

Most direct support for development of commercial energy storage resources has occurred at the state level. For instance, California adopted in 2014 a mandate to require utilities to create 1.3GW of energy storage capacity by 2022. Federal legislation has primarily been focused on research and development of innovative storage technologies that are not yet ready for private investment. For instance, in 2007, Congress passed the America COMPETES Act, which established the Advanced Research Projects Agency within the DoE (ARPA-E) to fund research and development of new innovative technologies including storage. In addition, recently, legislation was introduced by several US senators to establish an income tax credit for businesses and home use of energy storage (www.heinrich.senate.gov/press-releases/heinrich-introduces-bipartisan-bill-to-create-tax-credit-for-energy-storage). In the CPP, EPA noted the potential for energy storage to assist with the integration of renewable resources into the grid, but did not include energy storage resources as a way to reach pollution reduction targets.

From a regulatory perspective, FERC, in recent years, has issued several rules that, while not specifically aimed at energy storage resources, accommodate and encourage participation of non-traditional resources, including energy storage resources, in the wholesale energy markets. For instance, in 2011, FERC issued Order No. 755, requiring RTOs and ISOs to implement a ‘pay for performance’ compensation structure for frequency regulation service. Though not specifically aimed at energy storage resources, the intention of Order No. 755 was to ensure that flexible resources were receiving adequate compensation in the wholesale electric markets. In 2013, FERC issued Order No. 784, requiring all public utility transmission providers to have in their OATT a statement that it will take into account the speed and accuracy of regulation resources, as well as amended its accounting regulations to improve the accounting for and reporting of transactions associated with energy storage resources. Other FERC orders since, such as those concerning small generator interconnection policies and frequency response, also are intended to ensure RTO and ISO rules do not discriminate against newer technologies. Most recently, in April 2016, FERC commenced an informational proceeding to examine ‘whether barriers exist to the participation of electric storage resources in the capacity, energy, and ancillary service markets potentially leading to unjust and unreasonable wholesale rates’ (www.ferc.gov/industries/electric/indus-act/rto/A-4-Presentation.pdf). In some RTO and ISO markets, steps have been taken to revise market rules to improve the ability of storage resources to participate; for example, recently FERC approved changes to the California Independent System Operator Inc. (CAISO) tariff to allow market participants to submit state of charge as a bidding parameter, allowing storage providers flexibility in their offers. However, in an order issued in February 2017, FERC affirmed that market rules in MISO do not accommodate the unique physical and operational characteristics of energy storage resources. Other RTO and ISO markets, namely PJM and ISO New England, have identified disparities in the barriers to entry for storage resources (eg, penalties that are disproportionate to those for traditional resources owing to technological characteristics).

Recently, regulators at both the state and the federal level have undertaken efforts to reduce regulatory barriers in order to facilitate the integration of energy storage into the grid. Most notably, in February 2018, FERC issued Order No. 841, a landmark order that will pave the way for integrating energy storage systems in US wholesale energy markets. Previously, existing market rules did not align well with the operational aspects of energy storage systems, as the rules were created with traditional baseload resources in mind. Order No. 841 seeks to remedy this and directs each of the RTOs and ISOs under FERC’s jurisdiction to revise their tariffs to establish a participation model for energy storage resources that properly recognise their physical and operational characteristics. At the state level, regulators continue to issue regulations and craft policies focused on accommodating battery storage as well. For instance, in California, grid operators recently created a new product that is intended to value the capabilities of storage that is paired with solar or wind generation. And in Maryland, the state government recently created a new tax incentive programme aimed at residential and commercial customers who install qualified energy storage systems, the first of its kind in the United States. These efforts are expected to continue, with at least five states discussing or implementing legislation that would create similar tax incentive programmes.

Government policy

Does government policy encourage or discourage development of new nuclear power plants? How?

Historically, government policy has encouraged the development of new nuclear power plants. In 2010 the DoE launched a nuclear power programme in an attempt to jump-start the proposed construction of new nuclear plants by co-funding with the nuclear industry efforts to evaluate and bring new technologies to market. This included utilising a new NRC licensing process intended to streamline NRC approval of such projects. The DoE also put in place a Generation IV Nuclear Energy Systems initiative, which aims to develop new plant designs that minimise waste and are safer and more proliferation-resistant than today’s nuclear plant designs (www.nuclear.energy.gov/genIV/neGenIV1.html). EPAct 2005 also encouraged the construction of new nuclear plants by establishing a production tax credit. Under that plan, operators of the first 6,000MW of capacity from new nuclear power plants that are placed in service before 2021 will receive a production tax credit of 1.8 cents per kWh during the first eight years of the plant’s operation.

The US DoE Loan Guarantee Program was designed to promote development of the nuclear power industry through loan guarantees for the construction of new nuclear power plants in the United States. These loan guarantees help developers of new nuclear plants in the United States to obtain favourable financing terms, which is of critical importance when constructing plants with a projected price tag in the range of US$7 to US$10 billion per unit. Indeed, many companies that are considering building new plants have publicly stated that, absent a federal loan guarantee, they will not be able to finance and build their proposed projects. Seventeen companies building 21 nuclear units have applied for the guarantees. To date, a conditional loan guarantee of US$8.33 billion has been granted to the developers of two nuclear units in Georgia. The DoE’s Loan Guarantee Program also has earmarked an additional US$4 billion for the construction of new uranium enrichment facilities in the United States. Access to additional supplies of enriched uranium fuel will be critical to support the development of new nuclear plants in the United States. In May 2010, the DoE announced that it would grant a conditional loan guarantee of US$2 billion for the construction of a uranium enrichment plant in Idaho. In December 2014, the DoE Loan Guarantee Program issued a solicitation for an additional US$12.5 billion in available loan guarantees to support the construction of new large or small nuclear reactors, or provide upgrades to existing facilities, including US$2 billion set aside for uranium conversion or enrichment projects.

Since the Fukushima nuclear reactor crisis in March 2011, however, development of nuclear power plants in the United States has slowed, particularly with respect to licensing of new power plants or the relicensing of existing plants. Following an August 2012 decision by the US Court of Appeals for the DC Circuit ruling that the NRC did not sufficiently examine proper storage of nuclear waste in its regulations, the NRC suspended new licensing and licensing renewal for nuclear plants until a full reassessment of nuclear waste storage was completed. In September 2014, the NRC issued its new rule and resumed licensing decisions. The NRC’s new rule was upheld in a June 2016 decision by the US Court of Appeals for the DC Circuit. Additionally, in August 2013, the US Court of Appeals for the DC Circuit ordered the NRC to make a key decision regarding a proposed nuclear waste disposal site in Yucca Valley, NV, stating that the NRC did not have the legal authority to continue to delay making a decision regarding the licencing of the project (www.cnn.com/2013/08/13/us/nevada-yucca-mountain-order). That process remains ongoing, with DoE and NRC working to develop an Environmental Impact Statement. In August 2017, the NRC voted 2-1 to proceed with the ‘information-gathering stage’ of Yucca Mountain, enabling DoE to move forward on the licensing process. Whether and when this site becomes operational impacts the licensing and relicensing of nuclear power plants, as those decisions may require a permanent storage and disposal site for nuclear waste.

A new hurdle facing nuclear power is the relative low price of other energy resources, such as natural gas and subsidisation of renewable resources, which combine to reduce the economic viability of nuclear generation. In May 2014, for example, several nuclear power facilities failed to be selected to sell energy into a capacity market run by PJM Interconnection, Inc (PJM) because the price offered in the capacity market was insufficient to cover the costs of the nuclear facilities. As a result, the nuclear facilities must either cease production or find private purchasers and some utilities have announced that they will close certain nuclear plants. For instance, Exelon Corporation, operator of the largest nuclear fleet in the United States, announced it was permanently closing two facilities in Illinois, citing the fact that the facilities had lost $800 million over the last seven years (www.nytimes.com/2016/06/03/business/exelon-to-close-2-nuclear-plants-in-illinois.html?_r=0). It remains to be seen, however, whether changes to capacity auctions that seek to reward high-performing generating units, such as those planned for the PJM and ISO New England markets, will benefit nuclear power generators.

In July 2016, New York adopted a proposal that would allow nuclear facilities in the state to earn Zero Emission Credits (ZECs) as part of New York’s renewable energy standard. The ZECs would be calculated using a formula that uses the expected power costs in the region and the federal government’s calculation of the social price on carbon used by federal agencies use in rulemaking. Utilities in the state would then be required to purchase a pro rata share of ZECs, thus providing a value for the emissions-free energy produced by nuclear facilities. The result of this proposal was immediate - a New York nuclear facility that had been slated to close was purchased by a buyer that agreed to keep the facility open. Illinois passed legislation providing for similar credits in 2016. To date, legal challenges to the credits have failed and several additional states, including Ohio, Pennsylvania, New Jersey, and Connecticut, are considering similar initiatives.