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 the Energy Policy Act of 2005 (EPAct 2005) altered this traditional arrangement by vesting limited transmission siting authority with the Federal Energy Regulatory Commission (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 Federal Power Act of 1935 (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 services under the terms of an open-access transmission tariff (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. Independent system operators (ISOs) and regional transmission organisations (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.

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 that 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 obliged 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. There are significant tax benefits provided to renewable energy projects, mainly in the form of accelerated depreciation deduction and tax credits.

Most renewable projects are eligible for a cost recovery period of five years, which allows them to depreciate most of their eligible tangible assets, for tax purposes, over a five-year recovery period using the Modified Accelerated Cost Recovery System. In addition, the Tax Cuts and Jobs Act 2017 revised and increased the then existing bonus depreciation regime by allowing qualified renewable projects that are placed in service before 1 January 2023 to claim 100 per cent depreciation deduction for their qualified property in the year the project is placed in service. These rules are also applicable for used property acquired by the taxpayer from an unrelated party and meets other requirements. The bonus depreciation percentage is phased down based on the time the project is placed in service, as shown below. If a project is placed in service:

  • before 1 January 2023, there is 100 per cent bonus depreciation;
  • in 2023, there is 80 per cent bonus depreciation;
  • in 2024, there is 60 per cent bonus depreciation;
  • in 2025, there is 40 per cent bonus depreciation;
  • in 2026, there is 20 per cent bonus depreciation; and
  • after 2026, it is not eligible for bonus depreciation.

 

Allowing renewable projects and investors in such projects to deduct, for tax purposes, their qualified depreciable basis over a five-year period (or in a single year, in the case of the 100 per cent bonus depreciation) reduces their own tax liability and accelerates the rate of return on these investments.

Other significant tax benefits for renewable projects are the production tax credit (PTC) under section 45 of the Internal Revenue Code of 1986 (the Code) and the investment tax credit (ITC) under section 48 of the Code.

The PTC, most commonly associated with wind energy projects, provides taxpayers a tax credit of US$0.025 (as of 2020) for each kilowatt-hour (kWh) of electricity produced and sold to an unrelated taxpayer during a 10-year period after the date the wind project is originally placed in service. In addition to PTCs associated with wind projects, the following renewable technologies could also be eligible for PTC: biomass, geothermal, landfill gas (municipal solid waste), trash (municipal solid waste), marine and hydrokinetic facilities, and hydroelectric.

The PTC is available for most qualified renewable energy systems for facilities that have commenced construction before 1 January 2021. 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. In December 2019, this period was extended by one year pursuant to a 2019 year-end federal government budget appropriations bill (the 2019 Extenders Bill). Following this extension, qualified projects are eligible for PTC, based on the time the construction of the facility began, as shown below. Project that commenced construction:

  • prior to 1 January 2017 are eligible for 100 per cent of the PTC amount;
  • during 2017 are eligible for 80 per cent of the PTC amount;
  • during 2018 are eligible for 60 per cent of the PTC amount;
  • during 2019 are eligible for 40 per cent of the PTC amount;
  • during 2020 are eligible for 60 per cent of the PTC amount; and
  • after 2020 are currently not eligible for any PTC.

 

The Internal Revenue Service (IRS) provides a safe harbour to determine when a project will be deemed to have begun construction. In addition, projects that began construction in a specific year need to reach commercial operations date and be placed in service within the four-year period starting at the end of the year construction begun to meet the safe harbour.

In May 2020, recognising the impact of the covid-19 pandemic on the renewable industry and addressing the industry’s concerns, the IRS issued guidance extending the safe harbour period, for projects that began construction in 2016 or 2017. These projects will now have a five-year period to complete their construction and be placed in service, in lieu of the prior four-year period. As such, wind projects that began construction in 2016 now have until the end of 2021 to be placed in service to be eligible for the 100 per cent PTCs. Similarly, projects that began constructions in 2017 now have until the end of 2022 to be placed in service to be eligible for the 80 per cent PTCs.

The ITC, most commonly associated with solar facilities, provides taxpayers with a one-time tax credit equal to an applicable percentage of the project’s qualified cost at the year the project is placed in service, so long that the project is placed in service before 1 January 2024. Similar to the PTC, the ITC is also subject to phase down, and qualified projects are eligible for ITC based on the relevant applicable percentage, based on the time the construction of the facility began, as shown below. Projects that commenced construction:

  • prior to 1 January 2020 are eligible for 30 per cent of ITC;
  • during 2020 are eligible for 26 per cent of ITC; and
  • during 2021 are eligible for 22 per cent of ITC.

 

Commercial and utility scale projects that commenced construction during or after 2022 (or that commence construction prior to 2022 but are not placed in service before 1 January 2024) are eligible for 10 per cent ITC.

As provided for projects that are eligible for PTC, the IRS also provides a similar safe harbour for ITC-eligible projects to determine when such project will be deemed to have begun construction. Projects that began construction in a specific year also needs to reach COD and be placed in service within the four-year period starting at the end of the year construction has begun (but not later than 1 January 2024), to meet such ‘Safe Harbor’.

The US Department of Energy 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. 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. Moreover, as of August 2020, 30 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, and eight others (and one US territory) have set voluntary goals for adopting renewable energy resources. As of March 2015, 20 of these states include combined heat and power or waste heat recovery, or both, as an eligible resource.

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 obliged 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. In July 2020, FERC issued Order No. 872, implementing many significant revisions to PURPA, notably aimed at increasing state-level flexibility relating to variable rates for purchases of energy from renewable generation (qualifying facilities). In addition, Order No. 872 lowers the threshold of QFs from 20 megawatts (MW) to 5 MW, enabling electric utilities to more easily terminate legally enforceable contractual obligations to purchase energy from those small power production facilities.

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) has 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 (eg, cap-and-trade measures) and foreign policy initiatives could impose additional costs on electricity generators using carbon-rich fossil fuels. State or federal governments could subsidise renewable energy and carbon mitigation initiatives by surcharges on electricity generation or consumption.

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 the EPA’s authority to regulate existing power plants for greenhouse gases so long as they are being regulated for other pollutants as well.

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 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 (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 2009 the EPA issued a landmark rule establishing an ‘endangerment finding’ under the CAA – a determination that greenhouse gases, including carbon dioxide, are a threat to human health. As such, the EPA is required to regulate greenhouse gasses under the statutory directive of the CAA. In June 2019, the EPA issued a new final rule known as the Affordable Clean Energy (ACE) rule. The ACE rule established guidelines for states to develop plans and programmes regarding greenhouse gas emissions from existing coal-fired power plants. According to the EPA, approximately 600 coal-fired electric generating units at 300 facilities in the United States are now 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 ACE rule empowers states to craft plans establishing standards of performance for existing sources. Upon evaluation of those submittals, the EPA ultimately determines the best system of emission reduction (BSER). The EPA pre-emptively designated a range of candidate technologies that may be used to demonstrate the BSER for coal-fired power plants. In the ACE rule, the EPA defines the BSER as a technological solution to improve the heat rate efficiency of individual coal-fired units. Notably, the timelines for states to comply with the ACE rule to develop their plans for the EPA are particularly lengthy.

Industry observers and have expressed scepticism over the ACE’s rule’s viability. Many states, environmental protection organisations and public health groups have sued the EPA in consolidated proceedings, starting in September 2019 at the US Court of Appeals for the District of Columbia Circuit. Under the rule, ACE directs states to set relatively modest limits on emissions from power plants, and these limits can be achieved with upgrades to existing coal power plans. Opponents argue the effect therefore is to increase greenhouse gas emissions by allowing coal facilities to stay operational instead of reducing emissions through retirements to coal facilities and shifting resources to less-polluting sources (eg, natural gas or renewable sources). The EPA, under a 2007 Supreme Court decision, is required to regulate greenhouse gas emissions under the CAA, and opponents argue the ACE fails to do so by allowing for greenhouse gas emissions to increase. On the other hand, utility companies and others in the power sector stand to benefit by saving hundreds of millions of dollars in compliance and reporting costs.

Proponents of renewable energy are concerned that the ACE rule would slow development as well as exacerbate the effects of climate change. However, low natural gas prices and other environmental regulations are still expected to lead to the retirement of coal-fired generation and an increase in natural gas-fired generation. This in turn will increase the demand for natural gas resources. As a result, natural gas prices could rise and there will be opportunities for the development of supporting infrastructure, such as extraction or transportation. Irrespective of the enabling regulatory environment, utilities will continue to need to devote additional investment capital toward developing new generating capacity to replace the loss from the retirement of coal-fired plants. However, there may be some offset by a decreased demand in electricity as consumption becomes more efficient through technological advancements.

Despite the uncertainty, the development of renewable resources is expected to continue. This is due in large part to state initiatives aimed at incentivising the development of renewable resources and technological developments making the use of renewable resources more and more economical. However, the increased integration of renewable resources into the electric grid raises issues around grid reliability. In general, FERC and the North American Electric Reliability Corporation 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 fluctuates. In addition, a number of utilities have closed or announced plans to shut down certain, mostly older, less efficient, coal power plants.

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 1.3 gigawatts 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 Department of Energy (DOE) to fund research and development of new innovative technologies including storage.

In addition, during 2019, a piece of legislation was introduced in the US Congress to add stand-alone energy storage to the list of technologies eligible for the federal ITC. The bill was broadly supported by the industry. However, this bill was not enacted and furthermore, the 2019 Extenders Bill ultimately did not include a specific ITC for stand-alone energy storage batteries.

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 amend 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. 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’. 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 tariff 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 the Midcontinent Independent System Operator do not accommodate the unique physical and operational characteristics of energy storage resources. Other RTO and ISO markets, namely PJM Interconnection Inc (PJM) and ISO New England, have identified disparities in the barriers to entry for storage resources (eg, penalties that are disproportionate to traditional resources owing to technological characteristics).

Recently, regulators at both the state and 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 sought to remedy this and directed 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.

Each regional grid operator has since submitted a compliance filing, at a minimum, outlining its proposed participation model and intended effective date. While the overarching goal is the same, each approach varies owing to the unique market of each RTO and ISO as well as their current degree of electric storage integration. In May 2019, FERC affirmed its guidance on electric storage by issuing Order No. 841-A. This clarifying order preserved the core tenets of Order No. 841 and refused to include a provision proposed by intervenors that would have allowed states to opt out of the participation model requirement.

Industry groups and the National Association of Regulatory Utility Commissioners (NARUC) opposed the mandate furnished in Order Nos. 841 and 841-A, and in May 2020, argued before the United States Court of Appeals for the District of Columbia Circuit (the DC Circuit) to invalidate FERC compelling states to incorporate electric storage. NARUC and the industry groups claimed that FERC contravened the Federal Power Act (FPA) by infringing on the jurisdiction granted to states over local electricity distribution systems. The principal argument centred on the physical nature of those local systems – typically under state purview – and the logical extension that utilising those systems to integrate storage on wholesale markets would unlawfully intrude into federal jurisdiction. Additionally, the industry groups and NARUC argued that providing an ‘opt-out’ mechanism in Order No. 841 would be an appropriate legal remedy.

On 10 July 2020, the DC Circuit denied the petition. In the decision, the Court contemplated the line between federal and state jurisdiction in this matter, siding with FERC in its application of the FPA.

The DC Circuit ultimately determined that a state cannot mandate opting out of policies that integrate storage because the states do not have the authority to block sales of any resource in wholesale power markets. Under the FPA, states are precluded from delegating which resources are able to participate in wholesale markets – such an action would clearly invade federal authority vested in the FPA where FERC holds jurisdiction over wholesale (ie, federal) facilities and markets. Conversely, if FERC had attempted to enact an order pertaining to retail (ie, state) markets, the line would be drawn in favour of states’ jurisdictions and FERC would have been rebuffed.

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. As is common with transmission projects and rate proposals, most utility-scale electric storage installations are subject to approval by a state public utility commission (or other agency with a similar remit). Public utility commissions are conducting assessments and soliciting stakeholder feedback regarding potential multi-use applications of electric storage. These agencies are contemplating how to modify existing tariffs or market rules in order to incorporate storage without contravening contractual arrangements or provisions. As it stands, state utility regulators in California, Hawaii, Massachusetts, Minnesota, New York and Texas are undertaking such efforts relating to multi-use applications.

Solar-plus-storage projects are emerging as more viable in certain markets, in large part owing to evolving consumer preferences, net metering programmes and revisions to utility rate tariffs that carve out provisions for storage. With the exception of early adopters, the capital-intensive nature of this burgeoning sector has mostly limited solar-storage pairings to markets with clear enabling policy environments such as California (Self-Generation Incentive Program) and Hawaii (Customer Self-Supply Program). The state of Hawaii has led the charge in arranging solar-plus-storage power purchase agreements. This may be somewhat attributable to high electricity costs (the highest in the United States, because of the proportion of imported conventional fossil fuel resources) but has been buttressed by a commitment to deploy electric storage installations alongside solar generation at both the utility and residential levels. Hawaii’s goal of achieving 100 per cent renewable resources by 2045 also spurs the solar-plus-storage boom.

Finally, many recent offshore wind solicitations in the United States have specifically included a requirement for electric storage (via batteries) and transmission. For instance, all three proposals selected in the Massachusetts offshore wind round earlier this year included either battery or hydroelectric storage as part of the project. With more states carving out specific goals for storage, their respective requests for proposals (RFPs) for large solar or wind projects, or both, are likely to include similar requirements. The 300 MW RFP in Hawaii held in early 2018, and scheduled for installation by 2022, included both solar and wind, as well as the option to include energy storage in the bidding.

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. EPAct 2005 also encouraged the construction of new nuclear plants by establishing a production tax credit. Under that plan, operators of the first 6,000 MW 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 the 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 billion 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 the 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, Nevada, stating that the NRC did not have the legal authority to continue to delay making a decision regarding the licensing of the project. 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 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. 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 rule-making. 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.

Regulation of electricity utilities – transmission

Authorisations to construct and operate transmission networks

What authorisations are required to construct and operate transmission networks?

Construction of transmission facilities is primarily a state-regulated function, but federal authorities have jurisdiction over siting on federal lands, and multi-state projects may require the authorisation of several states. Historically, this fragmented system for siting new power lines, in addition to other factors such as regulatory uncertainty on the state and federal levels associated with transmission cost recovery, has been a significant barrier to the development of new transmission in the United States. The Energy Policy Act of 2005 (EPAct 2005) provides tools to facilitate new construction and improvements to the existing transmission infrastructure.

EPAct 2005 directed the Department of Energy (DOE) to conduct a nationwide study of electric transmission congestion and identify areas in which transmission capacity constraints or congestion adversely affects consumers and designate such areas as national interest electric transmission corridors (NIETCs). The most recent draft nationwide electric transmission congestion study was published in August 2014, but it did not propose nor designate any new NIETCs. EPAct 2005 gave the Federal Energy Regulatory Commission (FERC) supplemental permitting authority to ensure the timely construction of transmission facilities to remedy transmission congestion in those corridors. The DOE initially designated two such corridors in 2007, but the US Court of Appeals for the Ninth Circuit vacated and remanded the designations to the DOE for further proceedings in February 2011. The DOE announced that it will collaborate with FERC to prepare drafts of transmission congestion studies and environmental analyses for proposed NIETCs in the future. In addition, the US Court of Appeals for the Fourth Circuit limited FERC’s supplemental backstop siting authority, ruling that it applied only in situations where a state refuses to act on a permit application or imposes uneconomic conditions, but determined FERC lacked the authority to overrule a state denial of a permit application. Thus, a state may be able to circumvent FERC backstop siting authority by properly denying an application.

EPAct 2005 also provides a mechanism for the private use of the eminent domain power of the US government, where necessary, to obtain property for transmission infrastructure projects. In addition, EPAct 2005 requires that the federal government identify rights of way across federal lands that can be made available for siting electric transmission.

On 21 July 2011, FERC issued Order No. 1000, a final rule on Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities. The goal of Order No. 1000 is to ensure more reliable transmission service at just and reasonable rates. Order No. 1000 lays out certain requirements for coordinating transmission planning and allocating transmission costs so that transmission planners seek the most efficient and cost-effective way to meet needs in their respective regions and between regions. The implementation of Order No. 1000 is left largely to public utility transmission planners, which were directed to submit compliance filings in October 2012. The process of review, clarification and refiling is largely still underway for most transmission planners and as a result, the impact of the order is still evolving. In 2016, FERC convened a technical conference to assess the progress of implementing Order No. 1000.

 

Operation

FERC issued a series of orders, beginning with Order No. 890, which were intended to eliminate the broad discretion that transmission providers had in calculating available transfer capacity (ATC), increasing non-discriminatory access to the grid and ensuring that customers are treated fairly in seeking alternative power supplies. Since Order No. 890-A, transmission providers have implemented new service options for long-term firm point-to-point customers and adopted modifications to other services. Instead of denying a long-term request for point-to-point service because as little as one hour of service is unavailable in the course of a year, transmission providers are now required to consider their ability to offer a modified form of planning redispatch or a new conditional firm option to accommodate the request. This increases opportunities to utilise transmission efficiently by eliminating artificial barriers to the use of the grid. This standardisation reduces the potential for undue discrimination, increases transparency, and reduces confusion in the industry that resulted from the prior lack of consistency.

Also, FERC regulations require the posting of ATC values associated with a particular path, not available flowgate capacity values associated with a flowgate. With respect to energy and generation imbalance charges, a transmission provider must post the availability of generator imbalance service and seek imbalance service from other sources in a manner that is reasonable in light of the transmission provider’s operations and the needs of its imbalance customers. FERC also limited rollover rights to contracts with a minimum term of five years. In Order No. 890-B, FERC reiterated that a power purchase agreement must meet all of the requirements for designation as a network resource in order to be designated by the network customer or transmission provider’s merchant functions.

Eligibility to obtain transmission services

Who is eligible to obtain transmission services and what requirements must be met to obtain access?

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 Federal Power Act of 1935 (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.

Government transmission policy

Are there any government measures to encourage or otherwise require the expansion of the transmission grid?

Pursuant to EPAct 2005, FERC has established incentive-based rate treatments to encourage investment in and expansion of the US’s aging transmission infrastructure. FERC Order No. 679, issued in 2006, includes a number of key provisions to promote transmission investment, including:

  • incentive rates of return on equity for new investment by public utilities (both traditional utilities and stand-alone transmission companies);
  • a higher rate of return on equity for utilities that join or continue to be members of transmission organisations (eg, regional transmission organisations (RTOs) and independent system operators (ISOs)); and
  • various advantageous accounting methods, including:
    • full recovery of prudently incurred construction work in progress, pre-operation costs, and costs of abandoned facilities;
    • use of hypothetical capital structures for rate making purposes;
    • accumulated deferred income taxes for stand-alone transmission companies;
    • adjustments to book value for stand-alone transmission company sales or purchases;
    • accelerated depreciation; and
    • deferred cost recovery for utilities with retail rate freezes.

 

In Order No. 679 and Order No. 679-A, FERC extended incentive rate treatments to all utilities joining ISOs or RTOs, irrespective of the date they join. However, this incentive does not apply to the transmission rate base that has already been built, as the incentive’s purpose is to attract new investment in transmission.

Rates and terms for transmission services

Who determines the rates and terms for the provision of transmission services and what legal standard does that entity apply?

FERC has jurisdiction over unbundled transmission services (including transmission services provided over low-voltage facilities) provided by public utilities to wholesale customers or to retail customers with direct access. The states have jurisdiction over bundled retail service (namely, a combined generation and delivery product sold to retail customers) where direct access is not available. Court decisions and the interconnectivity of the transmission grid in the continental United States have led to an expansive view of what constitutes transmission service in interstate commerce in all areas of the United States except Alaska, Hawaii and the Electric Reliability Council of Texas. The Federal Power Act of 1935 (FPA), however, reserves to the states jurisdiction over the local distribution of electricity.

FERC-jurisdictional utilities offering transmission services must do so under FERC-approved tariffs. Order No. 888 required jurisdictional electric utilities to submit pro forma open-access transmission tariffs (OATTs) that functionally unbundled transmission operations and services, and set forth rates for transmission and ancillary services. In 2007, FERC issued Order No. 890, which modified the pro forma OATT to better remedy undue discrimination by, among other things, providing greater transparency and consistency in the calculation of available transmission capacity, and requiring coordinated open transmission planning between regions.

Transmission providers are also required to maintain an open-access, same-time information system to publish information with respect to their transmission systems, including services, rates, and available transmission capacity as well as business rules, practices, and standards that relate to transmission services provided under the pro forma OATT.

Finally, the FPA empowers FERC to review rates and terms of transmission services to ensure that they are just and reasonable and not unduly discriminatory or preferential. Generally, tariffs and contracts for transmission services must be filed with FERC before service commences to allow an opportunity for Commission review, as well as public notice and comment. Because transmission services are a natural monopoly, Order No. 888 envisions that FERC will determine whether a particular tariff is just and reasonable via a traditional cost-of-service rate making inquiry that balances ratepayers and the utilities’ financial interests to realise a rate within the zone of reasonableness. Tariffs can be challenged for being unjust, unreasonable, unlawful or discriminatory.

EPAct 2005 authorises FERC to require transmission providers not subject to its jurisdiction to provide open access to their transmission system at terms and conditions comparable to those the unregulated entity provides to itself. An unregulated entity may be exempt from this requirement if it sells less than 4 million megawatt hours of electricity annually or if it does not own or operate the transmission facilities needed to operate an interconnected system. However, many of these regulated entities already provide open access based on reciprocity agreements with transmission providers.

Entities responsible for grid reliability

Which entities are responsible for the reliability of the transmission grid and what are their powers and responsibilities?

Since 1968, the North American Electric Reliability Corporation (NERC) has operated as the primary entity responsible for assuring the reliability of the grid. NERC was founded by the electric utility industry to develop and promote rules and protocols to enhance the reliability of the bulk power electric system in North America through a voluntary, self-regulatory process. EPAct 2005 added section 215 to the FPA, which provides for the creation of an Electric Reliability Organisation (ERO) to be the organisation responsible for establishing and enforcing reliability standards for the bulk power system in North America. In 2006, FERC certified NERC as the ERO. The ERO oversees an enforcement programme that includes compliance audit monitoring and reliability readiness review.

In 2007, FERC strengthened the reliability regime by approving mandatory reliability standards for the bulk electric system proposed by the ERO, approving delegation agreements between the ERO and eight regional entities and creating a new internal Office of Electric Reliability. The mandatory reliability standards apply to entities designated by NERC as users, owners and operators of the bulk electric system. Both monetary and non-monetary penalties may be imposed for violations of these standards. In July 2014, a revised definition of the bulk electric system came into effect. The new definition expands the scope of facilities that form part of the bulk electric system to facilities operated at or above 100 kilovolts, thereby covering entities that own or control these facilities with certain limited exceptions. However, in March 2015, FERC gave approval for NERC to develop a new risk-based assessment and registration initiative intended to reduce the regulatory burden and align compliance obligations with issues that pose a greater potential impact to reliability. Additional proposed NERC reliability initiatives include developing standards to minimise potential disruption from geomagnetic disturbance events as well as to create cybersecurity standards to protect operational infrastructure.

In addition, the replacement of coal-fired, nuclear or other conventional generation resources with natural gas-fired or variable energy resources stands to impact grid reliability. As such, grid operators, such as RTO and ISOs, will likely need to develop approaches to effectively manage capacity during hours of peak demand, as well as manage overgeneration during off-peak hours. For instance, PJM Interconnection Inc, the RTO tasked with administering the transmission grid and energy and capacity markets for the mid-Atlantic region, recently implemented a revised auction model for capacity called the ‘Capacity Performance Resource’ model intended to improve overall reliability. The new model was created after the ‘Polar Vortex’ in the winter of 2014 in which natural gas shortages resulted in the failure of multiple generating units. The Capacity Performance Resources structure contains bonus and penalty payments that are structured to provide greater assurance that energy and reserves will be available during instances of peak demand created as a result of emergency operating conditions. In addition, technological developments, such as improvements to grid forecasting and the development of smart grid technology, will likely assist grid operators in providing the flexibility needed to address the challenges presented by variable resources and decreased generation capacity from more traditional resources.

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11 August 2020.