The Energy Regulation and Markets Review: USA
Energy regulation in the United States is complex, broad and enforced by a variety of federal and state government entities. Further, it is continually evolving in response to global, national and regional events, supply–demand balance and other market shifts, political dynamics and priorities, and technological advances. As such, this chapter is intended to give an overview of the nature and scope of energy regulation and markets.
i The regulators
Multiple federal and state agencies, departments and other government entities regulate US energy development, the ownership, control and operation of electric energy assets, and natural gas and oil production, gathering, transmission, transportation and distribution, including with respect to the rates, terms and conditions of wholesale and certain retail services, as well as energy market rules.
The Federal Energy Regulatory Commission (FERC) is an independent federal regulatory agency established by the United States Congress (initially established as the Federal Power Commission) to license hydroelectric facilities and to regulate (1) wholesale sales of electric energy and natural gas, (2) the transmission of electric energy in interstate commerce and (3) the transportation by pipeline of natural gas in interstate commerce. Subsequently, FERC's authority was expanded to include the regulation of interstate shipments of certain liquid fossil fuels via pipelines, including crude oil, petroleum products and natural gas liquids, such as propane and ethane. FERC's authority is granted, and limited, by statutes, as amended over time, including the Federal Power Act of 1935 (FPA), the Natural Gas Act of 1938 (NGA), the Public Utility Regulatory Policies Act of 1978, the Natural Gas Policy Act of 1978, the Interstate Commerce Act of 1887, the Energy Policy (EP) Acts of 1992 and 2005, the Public Utility Holding Company Act of 2005 and the Department of Energy Organization Act of 1977 (the DOE Organization Act).
The Nuclear Regulatory Commission is an independent federal regulatory agency established by Congress to formulate policies and regulations governing nuclear reactor and materials licensing and safety. The Nuclear Regulatory Commission's authority is also granted, and limited, by statutes, including the Atomic Energy Act of 1954, as amended, and the Energy Reorganization Act of 1974, as amended.
The Department of Energy (DOE) is an executive department created in 1977 via the DOE Organization Act whose current mission 'is to ensure America's security and prosperity by addressing its energy, environmental and nuclear challenges through transformative science and technology solutions'. DOE is led by the Secretary of Energy, a member of the President's cabinet. FERC is an independent regulatory agency within DOE and, under the DOE Organization Act, DOE and FERC have sometimes overlapping and sometimes separate authorities under their relevant organic statutes, including the FPA and the NGA. For example, under the NGA, DOE is responsible for issuing authorisations to import and export natural gas to and from the United States, including liquefied natural gas (LNG), while FERC is responsible for issuing authorisations to construct and operate LNG import and export terminals.
Numerous other federal agencies and departments regulate certain aspects of the US energy industry, including the Department of Transportation's Pipeline and Hazardous Materials Safety Administration (PHMSA) and Maritime Administration, the Environmental Protection Agency, the Army Corps of Engineers, the Commodity Futures Trading Commission, the Federal Trade Commission and the United States Departments of Agriculture, Interior, State, Commerce and Justice. The production and gathering of crude oil and natural gas, the siting and construction of energy facilities (except hydroelectric and natural gas facilities regulated by FERC), and the distribution and retail sale of electric energy and natural gas are generally governed by individual state regulatory agencies. In many states, public utility regulation is carried out by public service commissions or public utility commissions (PUCs) or municipal agencies (or both). The jurisdiction of these state and local regulatory agencies over energy companies is created by state constitutions and statutes and, like most state regulation in the United States, is also subject to the supremacy of the US government under the United States Constitution and federal statutes, except in certain limited circumstances.
ii Regulated activities
Many aspects of energy development, generation, production, transmission, transportation and distribution are subject to some type of federal or state regulation.
FERC regulates the rates, terms and conditions of wholesale sales of electric energy in interstate commerce and the transmission of electric energy in interstate commerce. FERC also regulates the rates, terms and conditions of service on natural gas and oil pipelines. Entities making sales of FERC-jurisdictional products or services obtain rate approval from FERC. FERC rates for electricity transmission and interstate natural gas transportation and storage are typically either cost-based (i.e., based on the costs of providing the product or service, including a reasonable return on equity investment) or market-based (i.e., negotiated or market-determined). Rates for petroleum pipeline transportation services may be based on historical and projected costs, and most pipeline rates are adjusted based on changes in a producer price index that measures the average change over time in the selling prices received by US producers for their output (plus a FERC-specified adjustment). FERC also regulates entities subject to its jurisdiction with respect to matters that may affect rates, including accounting, record-keeping and reporting, and, with respect to companies regulated under the Federal Power Act, direct issuances of securities and direct and indirect transfers of control over FERC-jurisdictional facilities.
Under the NGA, FERC is authorised to approve the construction and operation of new (and the abandonment of existing) interstate natural gas pipeline and storage facilities, and LNG import and export terminals. Owners of natural gas facilities authorised by FERC (but not LNG terminals) may call on a federal power of eminent domain to condemn land on which to site approved facilities. As a condition to the construction of new natural gas pipeline and storage facilities, FERC may require natural gas companies, among other things, to conduct an 'open season', during which potential customers may subscribe to transportation or storage capacity on a non-discriminatory basis and existing customers may turn back capacity that may result in the downsizing or elimination of the new facilities. In exercising its rate jurisdiction over electricity transmission facilities and oil pipelines, and in conjunction with its open access requirements, FERC has also required open seasons for some or all new or expanded capacity on certain electricity transmission and oil pipeline facilities.
The NGA was amended in 2005 to expedite the licensing process for the construction of interstate natural gas pipelines and storage facilities, and to clarify and modify FERC's review and approval of the construction and operation of LNG import and export terminals. The 2005 amendments also codified FERC's existing policy of 'light-handed' regulation of LNG terminals by prohibiting FERC from regulating the rates, terms and conditions of service for LNG terminals, but only until January 2015. Since this date, FERC has not exercised any authority to regulate the rates, terms and conditions of service of LNG facilities, and instead has continued to allow LNG import and export terminals to charge market-based rates and to operate without imposing open access requirements. Under the FPA, FERC also has siting approval authority with respect to hydroelectric generating facilities to be constructed on navigable waterways. In 2005, Congress also gave FERC 'backstop' siting authority under the FPA to issue permits for the construction of transmission lines when DOE designates important 'national interest electric transmission corridors' (NIETC) for geographical areas experiencing transmission constraints or congestion that adversely affects consumers, although the scope of FERC's backstop siting authority and DOE's NIETC designation authority under the FPA remains unclear as a result of judicial decisions in the US Courts of Appeals.
The PHMSA regulates the safety of most US pipelines and LNG terminals. Although it is responsible for enforcement of US laws setting minimum pipeline and LNG safety standards, the PHMSA allows states to assume inspection and enforcement authority if the state has adopted the federal minimum standards into law.
Pipelines located in US waters on the Outer Continental Shelf are subject to regulation by the US Department of Interior under the Outer Continental Shelf Lands Act of 1953, as amended in 1978. Prior to the Deepwater Horizon oil spill in the Gulf of Mexico in 2010, the Department of Interior's offshore pipeline responsibilities were carried out by the Minerals Management Service. However, in 2010, these responsibilities were transferred to a new agency, the Bureau of Ocean Energy Management, Regulation and Enforcement, and then transferred again in 2011 to two new bureaus: the Bureau of Ocean Energy Management and Bureau of Safety and Environmental Enforcement (BSEE). Offshore pipelines located within three miles of the United States are also often subject to state regulation.
State PUCs generally regulate the distribution and delivery of electricity and natural gas to retail customers, including rates, terms and conditions for retail sales and distribution of electric energy and natural gas, and the safe and reliable delivery of electricity and natural gas to retail customers in the state. State PUCs may also regulate rates and operating conditions for intrastate natural gas pipelines and storage services and for intrastate deliveries of liquid fossil fuels by pipeline. Siting approvals for the development and construction of new energy facilities are often required at the state or local government level.
iii Gathering, terminalling, processing and treatment of natural gas and oil
In states where natural gas and oil exploration and development is active, state agencies often possess regulatory authority over gathering (typically the collection and movement of resources by pipeline from production wells to a centralised processing station or other central collection point) of natural gas and oil. Many states have adopted rateable take and common purchaser statutes, which generally require gatherers to take or purchase, without undue discrimination, production that may be tendered to the gatherer for handling or sale. These statutes are generally enforced by PUCs only when a complaint is filed. The processing and treatment of natural gas and the storage and terminalling of oil are generally not regulated. However, FERC has jurisdiction over the gathering of oil by pipelines if the gathering is part of a movement of the oil in interstate commerce. FERC may regulate a natural gas gathering or processing line if it determines that the primary function of the line is the transmission (not gathering) of gas, and it may regulate an oil pipeline terminal or storage facility if it determines the facility is a necessary component of the pipeline's transportation function.
Regulation of the safety of natural gas gathering and processing facilities largely depends on the location and configuration of the facilities. Some facilities may be unregulated; others may be regulated by one or more state and federal agencies, to include the PUC, the PHMSA, BSEE and the Occupational Safety and Health Administration.
iv Ownership, market access restrictions and transfers of control
The Committee on Foreign Investment in the United States oversees foreign investment in existing companies and assets in the United States, including in the energy industry, with the President having ultimate authority to deny foreign investment that may adversely affect national security. Other than with respect to nuclear energy, there is little restriction on foreign ownership of energy assets in the United States under US energy-specific laws and regulations.
FERC approval is generally required for the direct transfer of natural gas facilities subject to FERC's jurisdiction, including transfers that spin down or partially remove facilities from FERC's jurisdiction (or reduce current services). In reviewing a proposed direct transfer of interstate natural gas facilities, FERC must determine whether the 'abandonment' of the facilities by the transferor is consistent with, and the ownership and operation of the facilities by the transferee 'is or will be required by', the 'present or future public convenience and necessity'. In both cases, FERC applies a public interest test that considers matters such as the effect of the transfer on competitive conditions and existing customers and services, including rates.
FERC also regulates the direct and indirect transfer of ownership or control over electricity transmission and generation facilities as well as the rate schedules pursuant to which electric energy or transmission service is provided. In reviewing a proposed transfer of electricity transmission or generation facilities and associated rate schedules, FERC must determine whether the transaction is consistent with the public interest, including the effects on competition (examining horizontal market power, vertical market power and barriers to entry), rates and regulation. FERC also considers whether the transaction would result in the cross-subsidisation of a non-utility affiliate of a public utility or the pledge or encumbrance of utility assets for the benefit of a non-utility affiliate of a public utility.
The PHMSA requires operators of regulated facilities to provide notice of certain transfers, name changes, acquisitions and divestitures no later than 60 days after the event. New operators must also be fully in compliance with the PHMSA regulations, including drug-testing, record-keeping and operator ID requirements, upon owning or operating an active or idled pipeline.
Certain states also require that entities obtain PUC approval prior to the direct and, in some jurisdictions, indirect transfer of assets subject to the jurisdiction of the PUC. While many state statutes require PUCs to evaluate whether a proposed transaction is consistent with the public interest, PUCs vary as to whether they interpret their jurisdiction as requiring a showing that the transaction will not result in net harm to the public or a showing that the transaction will affirmatively provide net benefits to the public.
Transmission/transportation and distribution services
i Vertical integration, unbundling and open access
During the past four decades, the federal government and many state governments have sought to replace traditional forms of cost-based regulation of services provided by vertically integrated monopolies with regulation designed to promote open access and competitive market forces.
Natural gas sector
Prior to the mid 1980s, the natural gas industry was fairly rigidly structured into three parts:
- producers that sold natural gas to pipeline companies;
- pipeline companies that resold and delivered that natural gas to distributors on a 'bundled' basis (combining the commodity cost of the natural gas with the cost of transportation service); and
- distributors that sold natural gas to retail customers.
Certain large industrial and electrical generating companies bought natural gas directly from producers or pipelines. And many local distributors had, in response to shortages in the 1970s, entered into long-term 'take or pay' contracts with pipelines for firm delivery of natural gas supplies for their customers. When gas prices fell in the 1980s, these distributors' contracts required payment for minimum volumes at the historic, higher prices. In an effort to address this issue, and open natural gas markets to widespread competition, FERC issued Order No. 380 in 1984 voiding contractual requirements that distributors purchase minimum quantities of natural gas from pipelines. The next year FERC issued Order No. 436 encouraging voluntary 'unbundling' of pipelines (i.e., transportation services not tied to purchases of natural gas from a transporting pipeline or its affiliates). Congress then passed the Natural Gas Wellhead Decontrol Act of 1989, lifting price controls on sales of natural gas by producers, and FERC adopted rules effectively deregulating the price of all other wholesale sales of natural gas. These orders were followed by FERC's landmark 'restructuring' order (Order No. 636) in 1992. Order No. 636 enhanced natural gas market competition by imposing new open access rules, requiring interstate pipeline and storage providers to offer unbundled transportation services at tariff rates on non-discriminatory terms and conditions set by FERC, promoting development of market hubs, allowing flexible use of receipt and delivery point rights and release of firm transportation and storage rights, among other reforms. Further, in 1992, the NGA was amended to effectively eliminate DOE permitting procedures associated with all natural gas imports, and exports to free-trade nations (coinciding with an agreement reached under the North American Free Trade Agreement to remove gas tariffs between the United States, Canada and Mexico).
FERC has continued to implement reforms to liberalise US natural gas markets by requiring compliance with standards of conduct that prohibit transmission function personnel from communicating non-public, competitively sensitive information to marketing personnel, requiring interstate natural gas pipelines to phase in standards adopted by the North American Energy Standards Board for internet-based information systems (to facilitate more efficient and transparent scheduling, reporting and use of available pipeline capacity), developing secondary markets for transportation services, market centres and customers' rights to segment transportation capacity into forward and backward hauls, and to use secondary receipt and delivery points on pipeline systems on a non-firm basis, and modifying scheduling timelines to facilitate improved gas-electric coordination. At the same time, many states also modified the exclusive retail franchises of distributors to permit open access competition in the retail sale of natural gas, while continuing to regulate natural gas utility distribution services provided under exclusive franchises. These reforms led to highly competitive natural gas sales markets in the United States, where only pipeline transportation and distribution services, and certain storage services, are subject to rate regulation.
The electricity sector was also initially dominated by vertically integrated franchised monopolies. Until the early 1990s, vertically integrated electricity utilities with monopoly retail franchises owned and controlled most of the facilities used for the generation, transmission and distribution of electricity within their franchised service territories. Many vertically integrated utilities were widely traded stock corporations, although some were owned by the US or state governments. Numerous municipally owned or cooperatively owned utilities also distributed electricity at retail, although these publicly owned utilities were typically smaller and more likely to be dependent on investor-owned utilities for transmission services to access generation resources located outside their service territories.
In 1978, Congress enacted the Public Utility Regulatory Policies Act to encourage the deployment of renewable and energy-efficient technologies by requiring electricity utilities to purchase electric power from generating sources using advanced technologies and eliminating all restrictions on the ownership of qualifying generating facilities. Non-utility companies demonstrated a high level of interest in building new power plants, which led in 1992 to Congress's elimination of all ownership restrictions on facilities generating electricity for sale at wholesale. At the same time, both the federal government and many states began to liberalise their wholesale and retail electricity markets, including state efforts to have state-regulated public utilities divest some or all of their electricity generation and federal efforts to make bulk power transmission facilities and distribution facilities available to others on an open access basis.
As part of the 1992 legislation, Congress amended the FPA to authorise FERC to order interstate transmission-owning public utilities to provide any electricity utility, federal power marketing agency, or any other person generating electric energy for wholesale sale, open and non-discriminatory access to their transmission facilities. As envisioned by Congress, this open access would allow bulk power consumers and suppliers to enjoy the benefits of competition in bulk power markets, as well as in those downstream retail power markets liberalised by states.
In 1996, FERC issued Order Nos. 888 and 889 to establish the foundation for the development of competitive bulk power markets by directing that bulk power transmission services be provided on an open access basis that is just, reasonable and not unduly discriminatory or preferential. Order No. 888 required that all FERC-jurisdictional transmitting utilities in the United States file a pro forma open access transmission tariff (OATT) and functionally unbundle their wholesale power services from their wholesale and retail transmission services. Order No. 888 also encouraged transmitting utilities to convey operational control of their transmission facilities to independent system operators (ISOs) or other independent regional transmission organisations (RTOs), which led to the formation of ISOs and RTOs in regions including the large majority of electrical load in the United States.
The pro forma OATT requires transmitting utilities to provide open, not unduly discriminatory access to their transmission system to transmission customers and addresses the terms of transmission service, including the terms for scheduling service, curtailments and the provision of ancillary services. Transmitting utilities are permitted to vary from the required pro forma terms of service if FERC finds that their proposed variations are equally, or more, conducive to the OATT's open access objectives. Order No. 889 required codes of conduct governing how participants in the wholesale power markets should interact with transmission service providers and the establishment of electronic bulletin boards (open access same-time information systems) for the posting of details regarding available transmission capacity.
Since Order Nos. 888 and 889, FERC has issued a range of major orders updating and expanding its open access policies to address such matters as:
- the formation of and participation in RTOs;
- pro forma procedures and agreements for interconnection of generation to the bulk power grid;
- changes to the pro forma generator interconnection procedures and agreements to facilitate interconnection of wind generators;
- general rules to facilitate more open and transparent planning and use of wholesale transmission facilities; and
- general rules regarding transmission planning and cost allocation.
FERC continues to consider whether reforms to its open access policies are necessary to eliminate possible barriers to the integration of wind, solar and other variable energy generation resources, as well as energy storage (e.g., batteries) and distributed energy resources, and to respond to market changes, including the growing deployment of small distributed generation resources, such as solar photovoltaic installations.
FERC's Order No. 1000, issued in 2011, adopted significant reforms of its rules on transmission planning and cost allocation established previously in Order No. 890. Order No. 1000 sought to address significant changes in the bulk power industry, including an increased emphasis on integrating renewable generation and reducing congestion, by implementing new policies to push transmission providers and planners to seek more reliable, efficient and cost-efficient solutions. The major reforms of Order No. 1000 include:
- requiring each public utility transmission provider to participate in a regional transmission planning process that produces a regional transmission plan and regional and interregional cost allocation methods for planned projects;
- requiring each public utility transmission provider to amend its OATT to describe procedures for considering transmission needs driven by public policy requirements established by state or federal laws or regulations, such as state renewable portfolio standards (RPS);
- removing from FERC-approved tariffs and agreements any federal right of first refusal for incumbent utilities to build and own certain new transmission facilities; and
- improving coordination between neighbouring transmission planning regions.
Order No. 1000 also provides that transmission upgrade cost allocations must be roughly commensurate with the benefits received. Various aspects of Order No. 1000, including its directives on cost allocation and rights of first refusal, were appealed to the US Court of Appeals for the District of Columbia (the DC Circuit). In 2014, the DC Circuit issued a unanimous decision affirming Order No. 1000. FERC continues to face significant challenges regarding Order No. 1000, its cost allocation principles and the implementation of those principles.
During the course of several years, the US electricity industry has evolved to become more dependent on natural gas caused by relative decreases in natural gas prices alongside increasing environmental regulations under various federal laws, leading to coal plant retirements. In addition, the increasing rate of penetration of intermittent renewable generation resources often requires natural gas-fuelled generation as a reliability backstop. The increasing reliance on natural gas for electricity generation, together with severe weather experiences across the United States in recent years, have continued to put pressure on the existing natural gas transportation infrastructure and highlighted several issues with respect to how the natural gas and electricity industries interact. In response, in 2015, FERC issued Order No. 809 adopting proposals to modify the scheduling practices used by interstate natural gas pipelines to provide additional contracting flexibility to firm natural gas transportation customers through the use of multiparty transportation contracts and revised nomination timelines.
Oil and liquids sector
Unlike interstate natural gas pipelines, oil pipelines engaged in interstate commerce have been regulated as common carriers (not public utilities) since the Interstate Commerce Act was extended to oil pipelines in 1906. As common carriers, oil pipelines must provide service to all customers without 'undue discrimination' or 'undue preference' to any customer, including affiliated customers and at rates that are 'just and reasonable.' The prohibition on undue discrimination and preference extends to periods when the pipeline is in 'pro-rationing', namely, the situation in which the pipeline must curtail specific shipments when customers' nominations exceed available capacity.
For most of the 20th century, the vast majority of oil pipeline mileage was owned by major oil companies with vertically integrated production, transportation, refining and distribution operations. This situation began to change in the latter part of the century in light of two developments. First, a change in US tax laws in the 1980s allowed companies engaged in (among other sectors) the transportation and storage of natural resources to be organised as master limited partnerships (MLPs), which provide certain tax advantages to their investors and, hence, make investments in those sectors financially attractive. Second, in 1996, FERC began issuing declaratory orders that approved then-novel rate and tariff structures that enhanced pipeline developers' ability to finance new pipelines. Specifically, when new or expanded oil pipeline capacity has been offered to all prospective shippers in a FERC-approved 'open season', FERC's orders provide advance regulatory approval of pipelines' long-term contract ('committed') rates and tariff structures that need not be supported by cost data. These two developments facilitated the development of pipelines by independent entities. Although many pipelines are still owned by vertically integrated oil companies, tens of thousands of oil pipeline miles are also owned by non-integrated companies.
Economic regulation of most of the bulk power transmission system in the continental United States is administered by FERC, including regulation of the rates, terms and conditions for the transmission of electric energy in interstate commerce. Most FERC-regulated transmission services are provided at embedded cost-of-service rates that provide a return of investment as well as a FERC-determined reasonable rate of return on common equity. FERC also has permitted 'merchant' transmission projects (i.e., transmission that is not included in a cost-of-service rate base) to charge negotiated rates for transmission service under certain conditions, including holding open seasons or solicitations for transmission service, demonstrating regional reliability and operational efficiency benefits and requirements that service be provided without undue discrimination or preference.
FERC is also charged with determining a just and reasonable rate of return on equity (ROE) for owners of FERC-jurisdictional transmission facilities. Historically, FERC established a 'zone of reasonableness' through a discounted cash flow (DCF) methodology to estimate a utility's allowed ROE in its cost-of-service rates and selected an appropriate ROE for transmission owners within that zone of reasonableness based on various factors. FERC typically selected the midpoint within the zone of reasonableness as the base ROE, with the potential to add to that if a proposed transmission facility satisfied the requirements for an incentive-based adder. However, in Opinion No. 531 issued in 2014, FERC made a ruling on a complaint challenging the base ROE for transmission owners in New England and, citing 'anomalous capital market conditions' resulting from the 2008 financial crisis, changed its method for determining the base ROE in that case and selected a base ROE at the midpoint of the upper half of a zone of reasonableness. In 2017, in Emera Maine v. FERC,2 the DC Circuit vacated and remanded Opinion No. 531, finding that FERC had failed to sufficiently explain that (1) the existing base ROE was unjust and unreasonable, and (2) FERC's setting of a replacement ROE at the midpoint of the upper half of the zone of reasonableness using the DCF methodology, rather than the midpoint of the overall zone of reasonableness, was just and reasonable. In response to Emera Maine and in a proceeding concerning complaints challenging the base ROE for transmission owners in the Midwest, FERC initially decided to use a hybrid approach combining four separate methodologies for estimating a utility's ROE–DCF, the capital asset pricing model (CAPM), expected earnings and the risk premium model. However, in late 2019, FERC issued Opinion No. 569 in the same proceeding, ordering the use of a hybrid approach equally weighting the results of its DCF and CAPM methodologies to establish the zone of reasonableness broken into risk-based quartiles (under which an existing base ROE is rebuttably presumed to be just and reasonable if it lies within the range of ROEs for the risk quartile for the relevant utility or utilities). This new method resulted in significantly lower base ROEs for the transmission owners in that case, and Opinion No. 569 is being challenged by a large number of transmission owners.
In 2005, Congress amended the FPA to direct FERC to develop rate incentives to encourage certain transmission development. In 2006, FERC issued regulations in Order No. 679 to provide, case by case, a variety of cost-of-service rate incentives for new transmission projects that improve reliability or reduce cost. In 2012, FERC issued a policy statement providing further guidance on incentive-based rates for electric transmission. The incentives available under the regulations and 2012 policy statement include incentive rates of return on equity for new investment (which is an adder to the base ROE as determined under FERC's applicable methodology for determining a utility's base ROE), use of a hypothetical capital structure during construction, full recovery of prudently incurred construction work in progress in rate base during construction, full recovery of prudently incurred costs of abandoned projects and accelerated depreciation. To obtain one or more of these incentives, an applicant must show that there is a nexus between the incentive being sought and the risks associated with the investment being made. In March 2019, FERC issued a notice of proposed rule-making to consider changes to its electricity transmission rate incentive regulations and policy, including a possible shift in its focus on granting incentives from the current project risks and challenges nexus test to an approach based on the benefits to electricity consumers.
Since 2000, FERC has also permitted certain merchant electricity transmission projects to charge negotiated rates for transmission service under OATT-based transmission service agreements. Initially, FERC required merchant transmission facilities to hold open seasons for the full capacity of a planned project. Beginning in 2009, FERC permitted certain merchant transmission project developers to allocate some portion of transmission capacity (generally not more than 75 per cent) through pre-subscription to 'anchor customers', who provide up front or assured continuing payments through long-term transmission service agreements to facilitate project construction. The remaining project capacity not committed to anchor customers will be made available to later customers selected through an open season process detailed in the project's OATT and these customers will be entitled to obtain service under terms and conditions generally comparable to those available to anchor customers. Since 2013, FERC has permitted merchant transmission developers to avoid formal open season requirements (instead relying on broad open solicitations with less strict parameters) and allocate up to 100 per cent of the capacity on a transmission project to a single customer, including an affiliate, if the developer broadly solicits interest in the project from potential customers and demonstrates to FERC that it has satisfied certain solicitation, selection and negotiation process criteria.
Rates for interstate natural gas transportation and storage are generally based on costs, including a reasonable return. Rates for service are established for new facilities when FERC certificates construction. Pipelines may change the rates based on a showing that a new cost-based rate is 'just and reasonable', and FERC or other affected parties may require prospective rate adjustments by showing that the existing rates are unjust and unreasonable. In 2009, FERC began a systematic and in-depth review of cost and revenue information that must be filed annually by pipelines, leading to the initiation of rate investigations of certain pipelines based on data suggesting that these were over-earning. FERC has continued initiating these investigations, typically targeting a few pipelines once a year or in alternate years. Most recently, in connection with changes in US tax law, FERC has initiated proceedings requiring reporting of updated cost and revenue data and has indicated that it will initiate rate investigations where these data suggest over-earning (unless the pipeline files to reduce its rates voluntarily).
Gas pipelines and storage companies are permitted to offer discounts below the maximum, cost-based rates approved by FERC (also referred to as the 'recourse rates') to meet competition. Any rate discounts offered by an interstate natural gas company must be offered on a non-discriminatory basis to all similarly situated customers. Between rate cases, the natural gas company must bear the cost of any revenue shortfalls attributable to discounts (i.e., it cannot charge higher rates to other customers to make up revenues lost because of discounting). Interstate pipelines and storage companies may also negotiate rates for services either above or below the recourse rate, as long as the customer retains the option to take service under the recourse rate. Independent storage companies are often permitted to charge competitive market-based rates based on a demonstration that they do not have significant market power.
Pipelines under FERC's jurisdiction that transport fossil fuel liquids (oil pipelines) may charge cost-based rates, or they may charge market-based rates if they can show that they lack significant market power in their origin and destination markets. FERC-regulated oil pipeline rates may be changed annually based on the US Producer Price Index for Finished Goods, plus a margin established by FERC every five years (currently 1.23 per cent). If, however, oil pipeline indexed rates become significantly higher than a cost-based rate, or any annual increase is substantially greater than actual cost increases, FERC may adjust the rates. FERC allows greater flexibility in rates, terms and conditions of service for interstate service using new or expanded oil pipeline capacity if offered to all shippers and prospective shippers in an open season. FERC permits oil pipelines to offer priority service (i.e., service not subject to pro-rationing during normal pipeline operations) for up to 90 per cent of new capacity if contract (committed) shippers pay rates above those paid by uncommitted (walk-up) shippers, and all shippers had an opportunity to contract for the new capacity in an open season conducted by the pipeline company.
iii Security and technology restrictions
Prior to 2005, the United States relied on voluntary compliance by participants in the bulk power industry with reliability requirements for operating and planning the bulk power system coordinated through the North American Electric Reliability Corporation (NERC) and various related regional entities. In 2005, Congress responded to a widespread August 2003 blackout throughout the north-east and Midwest states (and parts of Canada) by amending the FPA to provide for a system of mandatory, enforceable reliability standards to be developed by a FERC-certified electric reliability organisation (ERO), subject to review and approval by FERC. For purposes of approving and enforcing compliance with reliability standards, FERC has jurisdiction over the FERC-certified ERO, any regional reliability entities, and all users, owners and operators of the bulk power system, including public and government entities not otherwise subject to FERC jurisdiction under the FPA. FERC certified NERC as the ERO and in various subsequent orders has defined the bulk power system and approved a number of reliability standards proposed by NERC.
Federal law sets minimum safety standards for all natural gas and hazardous liquids pipelines, and provides for regulation of these facilities by the PHMSA. The PHMSA regulates pipeline facilities pursuant to its pipeline safety programme, which is implemented in cooperation with the states. Although the PHMSA has the authority to regulate all interstate pipelines, it may allow a state to act as its agent, subject to certain limitations. Also, states adopting laws meeting or exceeding the federal minimum safety standards may obtain a certification from the PHMSA to regulate intrastate pipelines. If a state's law does not meet the federal minimum safety standards, the PHMSA may decertify the state or exercise backstop authority to inspect and enforce federal pipeline safety laws. States are permitted to adopt and enforce standards that are more stringent than the federal minimum standards, which in many cases are overseen by each state's PUC. The security of LNG waterfront facilities and deepwater ports is regulated by the US Coast Guard pursuant to a number of federal laws, including the Maritime Transportation Security Act, the Ports and Waterways Safety Act, the Magnuson Act and the Deepwater Port Act.
Federal law and agency-specific regulations require that owners and operators of energy facilities protect sensitive security and critical energy infrastructure information from disclosure to the public, including electronic copies of the information stored in company operating systems, databases and computers. The United States has not currently adopted mandatory cybersecurity standards for pipelines, storage facilities or LNG terminals, although in response to growing concerns about cybersecurity and recently reported cyberattacks on major pipelines, new legislation and new rules are being considered and a new DOE Office of Cybersecurity, Energy Security, and Emergency Response was established in 2018. The electric, natural gas and oil industries are voluntarily implementing measures to maintain security and are cooperating with federal agencies to develop and implement safeguards.
i Development of wholesale electric energy markets
Throughout certain regions in the United States, ISOs and RTOs operate transmission facilities and administer organised wholesale electricity markets. FERC has prohibited any one set of market participants (including transmission owners) from controlling decision-making within an ISO or RTO. FERC's Order No. 2000 imposed significant regulatory requirements upon ISOs and RTOs regarding the independence of an energy market administrator, the performance of the energy markets and the elimination of discrimination. FERC leaves considerable discretion to market participants to determine an ISO's or RTO's governance structure, geographical scope and type of market services.
The following seven ISOs and RTOs currently operate in the United States: PJM Interconnection, LLC (PJM), New York Independent System Operator Inc (NYISO), ISO New England Inc (ISO-New England), Midcontinent Independent System Operator Inc (MISO), Electric Reliability Council of Texas (ERCOT), Southwest Power Pool and California Independent System Operator Corp (CAISO). Of these RTOs, only ERCOT is not subject to FERC's regulatory oversight under the FPA, as it is deemed to be electrically isolated from the rest of the transmission grid in the continental United States. (Similarly, Alaska and Hawaii are not subject to FERC's regulatory oversight under the FPA, as their respective electricity transmission systems are not connected to the interstate transmission grid in the continental United States.)
Each ISO and RTO offers different energy products in its organised markets. While all the existing ISOs and RTOs administer some form of bid-based markets for one or more energy products (i.e., when the highest price bid for the marginal quantity of supply that satisfies the quantity demanded in any relevant period sets the market price for the product within that applicable region, node or zone), some provide real-time and day-ahead markets, while others do not. In addition, some of the ISOs and RTOs offer forward markets for the sale of capacity (i.e., the ability to produce electric energy) separate from other energy products. The forward capacity markets are structured differently in each ISO and RTO, and the details associated with the ancillary service markets for these ISOs and RTOs differ as well. For example, following severe weather in 2013–2014 in the east of the United States, when demand was high and generation supply was unavailable for a variety of reasons, both ISO-New England and PJM sought to improve generator reliability during these periods by proposing significant changes to their forward capacity market rules. ISO-New England's proposed changes, referred to as performance incentive or pay for performance, were adopted in 2014, and PJM's proposed changes, referred to as capacity performance, were adopted in 2015. All capacity resources that clear ISO-New England's market became subject to pay for performance requirements beginning with the delivery year that commenced in June 2018. All capacity resources that clear the PJM market are subject to capacity performance requirements beginning with the delivery year that commences in June 2020. Both programmes eliminate most of the excuses for non-performance during a delivery year and increase the penalties for non-performance, and the financial assurances required to be posted by proposed capacity resources.
Each market has an independent market monitor, as FERC required by Order No. 719, but the nature and scope of the market monitors' roles differ. As a general matter, the independent market monitor within each ISO and RTO provides independent oversight over certain market issues, including with respect to market structure, conduct and performance issues. ISOs and RTOs that are interconnected to one another have special joint operating arrangements relating to the 'seams' between them. Moreover, CAISO has established and made available to other electric grids in the western United States that are neither ISOs nor RTOs a Western Energy Imbalance Market (Western EIM) that on a regional basis can automatically balance supply and demand and dispatch least-cost energy resources on a short-term basis. This system is intended to assist California and other states in the western United States to better manage and share their generation capacity reserves and integrate intermittent renewable generation resources. Electric grids in eight western states and British Columbia, Canada are active participants in the Western EIM and portions of the electric grid in two other western states plan to join by 2021.
ii Wholesale energy market rules and regulation
Each ISO and RTO develops its own market rules through the market participants' stakeholder approval process. Market rules for all ISOs and RTOs must be filed with and approved by FERC prior to implementation, except for ERCOT, whose market rules are subject to the exclusive jurisdiction of the Public Utility Commission of Texas.
iii Contracts for sale of electric energy at wholesale
The US electricity markets have a long history with bilateral power purchase and sale contracting at wholesale. Even when market participants are located within an applicable ISO or RTO (i.e., bidding or offering into the organised wholesale markets and scheduling flows through the ISO or RTO), market participants often enter into bilateral energy and capacity contracts as a means of hedging the volatility of market prices or providing a reliable source of supply. Bilateral contracts can be in the form of physical purchases and sales or financially settled purchases and sales. Some contracting parties use standardised industry form agreements, such as those developed by the Edison Electric Institute or the International Swap and Derivatives Association, and others negotiate individualised contracts. Physical sales of energy, capacity and ancillary services products in the wholesale markets are subject to FERC jurisdiction and associated contracts must either be filed with FERC or reported through quarterly reports.
iv Natural gas and oil commodity and transportation markets
Unlike in the electricity sector, there are no formal FERC-approved organised wholesale markets for oil and natural gas.
Sales of natural gas or oil commodities may be accomplished through trading platforms, such as the Intercontinental Exchange or bilateral contracts. As with purchase and sale agreements for electricity, bilateral agreements can be in the form of physical purchases and sales or financially settled purchases and sales. Some contracting parties use standardised industry form agreements, such as those developed by the North American Energy Standards Board, and others negotiate individual contracts.
Interstate natural gas pipelines are required to operate secondary markets for the transportation services they offer. Under FERC's rules, any shipper that has contracted for firm transportation service on a natural gas pipeline may release its contracted capacity to other shippers, either by publicly posting the availability of the pipeline capacity on an electronic bulletin board maintained by the pipeline and accepting offers for it, or, if certain criteria are met, in a privately negotiated, but publicly posted, transaction with prices capped at the pipeline's tariff rate. Also, to facilitate the development of natural gas markets, FERC has liberalised some of its rules designed to prevent shippers from capitalising on a pipeline's market power. Generally, FERC requires shippers to hold title to the natural gas they ship on interstate pipelines and prohibits shippers from buying natural gas at a receipt point and reselling the natural gas to the same company after transportation at the delivery point in a prearranged 'buy-sell' transaction. To allow brokers to aggregate transportation capacity and natural gas supplies, and to use transportation services more efficiently, FERC allows exceptions to its shipper-must-have-title rule under qualifying asset management arrangements. FERC also grants waivers of its shipper-must-have-title, buy-sell and capacity release rules when necessary to facilitate transfer of pipeline capacity in certain circumstances involving asset sales or corporate restructuring. It is unlawful for 'any entity' (not just regulated companies) to engage in a course of business or omission, or mislead, with intent to affect a FERC-jurisdictional market. Violation of FERC's market rules exposes the actor to the potential for significant civil penalties and enforcement action by FERC.
Given the limited scope of its jurisdiction over oil pipelines under the Interstate Commerce Act, FERC historically has refrained from involvement in crude oil marketers' use of interstate oil pipelines – except to ensure that the pipelines' rates, terms and conditions of service for all shippers are 'just and reasonable'. In November 2017, however, in response to a petition for declaratory order, FERC ruled that a marketing affiliate of an oil pipeline may not use its capacity on the pipeline to engage in 'buy-sell' transactions in which the price differential between the points of purchase and resale is less than the pipeline's filed rate between those two points. In January 2018, FERC granted rehearing of this order for purposes of further consideration requested by numerous parties, but it has not yet ruled on the merits of the rehearing requests. In February 2018, certain petitioners asked FERC to develop standards of conduct for oil pipelines similar to those applicable to the transportation and marketing functions of natural gas pipelines. That request is currently pending before FERC.
v Retail energy market regulation
Retail energy markets are regulated at the state and local levels. Across much of the United States, retail consumers buy electricity and natural gas from local utilities, many of whom remain vertically integrated, at rates and under terms and conditions set by local regulators. Since the mid 1990s, there has been a move in some states to unbundle commodity generation or natural gas service from distribution services and allow retail consumers to purchase these commodity services from competitive retail suppliers. Between 1995 and 2002, a large number of states, including California, Texas and most of the states in the North-East, introduced retail competition for electricity and natural gas, and in some instances required local utilities to divest or formally separate their electric generation, as part of industry reforms generally referred to as 'electricity restructuring'. These restructuring efforts also included various mechanisms to provide short-term savings to retail consumers, and mechanisms to protect consumers from market volatility in the wholesale markets and requirements that distribution utilities serve as a provider of last resort for retail consumers who cannot (or do not choose to) obtain commodity service from a competitive supplier. At the same time, in many states, distribution utilities were required to charge prices for commodity service at levels above projected market prices to create a competitive opening for other retail suppliers.
During 2000 and 2001, there was an extended period of extreme volatility in wholesale electricity and natural gas markets in the western states, which had a severe negative effect on the financial conditions of the restructured utilities in California and ultimately compelled the state to become a significant buyer of last resort in the wholesale electricity markets and ended retail competition for most retail consumers in California. Following this crisis, further efforts at electricity restructuring at the retail level in the United States largely came to a standstill and retail competition was suspended or rescinded in several states. As of 2018, 16 states and the District of Columbia allow for retail competition. However, regulators in New York State took action in early 2016 to limit retail competition for the majority of residential and small commercial customers by requiring retail suppliers to serve mass-market customers under contracts that either guaranteed certain customer cost savings or guaranteed a portion of retail supply from renewable energy sources. This action to limit retail competition was vacated by a state court. In late 2016, regulators in New York initiated a proceeding to determine whether retail suppliers should be completely prohibited from serving their current product offerings to mass-market customers. In 2019, New York instituted new rules that restrict mass-market retail competition by imposing additional requirements that retail suppliers must satisfy to offer mass-market retail service and introducing new limitations on the types of products that retail suppliers may offer to mass-market customers. Since the early 2000s, a number of states have allowed for the creation of community choice aggregation (CCA) arrangements, whereby a local entity, often one created by a local government, can aggregate the buying power of individual retail customers within a defined local jurisdiction to secure alternative energy supply arrangements. This alternative energy supply is delivered to participating retail customers by the existing electric distribution utility. The presence of CCA arrangements has increased significantly since 2014, especially in California, where utility regulators have estimated that as much as 85 per cent of retail electric load served by the state's investor-owned utilities will participate in these arrangements by the end of 2025. As of 2019, nine states had CCA-enabling laws and as of 2017 there were estimated to be approximately 750 CCAs serving about 5 million customers in eight states which then had CCA-enabling laws.
Renewable energy and conservation
i Development of renewable energy
The United States does not have a single comprehensive policy regarding the development of renewable energy. Rather, the federal government provides, or has provided, various targeted tax incentives and financing support programmes, while a large number of states have implemented renewable portfolio or clean energy standards and net metering, tax incentives and installation cost rebate programmes for distributed renewable generation resources. There have been a series of unsuccessful efforts by Congress to mandate a federal renewable or clean energy standard, most notably in the comprehensive greenhouse gas (GHG) cap and trade and clean energy legislation that passed in the House of Representatives in 2009. In 2014, the Environmental Protection Agency issued regulations regarding carbon dioxide emissions from new and existing electric generating facilities (the latter referred to as the Clean Power Plan), which would limit the rate of emissions of carbon dioxide per megawatt-hour of generation output. The Clean Power Plan proposed in part increased generation output from renewable energy resources, and avoided fossil fuel-fired generation output from end-use energy efficiency measures, as compliance mechanisms. In February 2016, the US Supreme Court issued a stay, halting implementation of the Clean Power Plan pending the resolution of legal challenges to the programme in court. The Trump administration took initial steps in 2017 to repeal the Clean Power Plan and proposed the Affordable Clean Energy Rule (referred to as the ACE Rule) in August 2018 to replace it. These steps culminated on 8 July 2019 in a final rule repealing the Clean Power Plan and replacing it with the ACE Rule. The latter is more narrow in scope than the Clean Power Plan, only applying to coal-fired electricity generating units. The ACE Rule removed numerical standards and targets for carbon dioxide reductions in favour of state standards for electricity generating units, and prevents states from adopting market-based or flexible compliance mechanisms (i.e., emission reduction credits or allowances) between electricity generating units to satisfy the standards. The final rule does not provide presumptively approvable standards or model plans, but instead calls on states to set standards based on unit-specific considerations. The rule became effective on 6 September 2019 and is currently subject to legal challenges by several state attorneys general.
The federal government provides, or has provided various tax incentives for renewable energy, including:
- a production tax credit (PTC) (per energy generated) for wind, geothermal, biomass and some other renewable energy resources (but not solar and fuel cells) for 10 years from the date the renewable energy facility is placed in service;
- an investment tax credit (ITC) (based on qualified project costs) for a wide range of renewable energy resources (including solar and fuel cells) and for combined heat and power generation; and
- special accelerated depreciation rules that provided five-year depreciation for a range of renewable energy resources placed in service from 2008 to 2012.
The PTC was first implemented under the EP Act of 1992 and was extended to include projects commencing construction prior to 1 January 2020, with a step down of the credit amount for projects commencing construction after 31 December 2016. The estimated tax credit at the beginning of the programme was 1.9 cents per kilowatt-hour (kWh), drawing down to 1 cent/kWh for projects commencing construction in 2019. The PTC was extended in December 2019 for projects commencing in 2020 at an estimated tax credit of 1.5 cents/kWh. The ITC was first implemented under the EP Act of 2005 and was most recently extended until 2022, with a gradual step down of the credits between 2019 and 2022. To be eligible for the 30 per cent ITC, a commercial solar photovoltaic system must have commenced construction on or before 31 December 2019. The tax credit will decrease to 26 per cent for systems commencing construction in 2020, 22 per cent for systems commencing construction in 2021, and 10 per cent for systems commencing construction in 2022 or thereafter. The American Recovery and Reinvestment Act (ARRA) allowed taxpayers eligible for the PTC to take the ITC in lieu of the PTC for projects installed between 2009 and 2013 (between 2009 and 2012 for wind). ARRA also allowed taxpayers eligible for the ITC (including those taking the ITC in lieu of the PTC) to receive a cash grant from the US Treasury Department in lieu of the ITC for projects that commenced construction by the end of 2011, although projects not yet placed in service were subject to reduced cash grants under an automatic sequestration law that took effect in early 2013, affecting expenditure by the federal government. The federal government estimates that as at July 2012 it had provided approximately US$13 billion in cash grants for more than 45,000 renewable energy projects, although the majority of the funding was awarded to larger wind projects.
The DOE's Loan Programs Office (LPO) has operated various loan guarantee programmes for advanced technology and clean energy projects established under Title XVII of the EP Act of 2005 and Sections 1703 and 1705 of ARRA. As of early 2019, the LPO has approved more than US$30 billion in loans and loan guarantees for more than 30 projects, and has more than US$40 billion available for loans and loan guarantees. As at January 2017, the LPO had issued solicitations making available up to US$4.5 billion in loan guarantees to support innovative renewable energy and efficient energy projects. The LPO also has solicitations outstanding for advanced fossil energy projects, advanced nuclear energy projects, advanced technology vehicles manufacturing and tribal energy development projects. As at February 2020, LPO has US$8.5 billion in loan guarantee authority for advanced fossil energy projects, including carbon capture projects.
More than half of all states and the District of Columbia have renewable energy portfolio standards or goals requiring retail electric utilities to deliver a certain amount of electricity from renewable or clean energy resources. These standards and goals vary greatly across the states, both in terms of their levels and target dates (generally between 10 per cent and 30 per cent by no later than 2020, though some states, such as Hawaii and, more recently, Virginia, have target levels as high as 100 per cent by 2045) and the types of energy resources that qualify (e.g., fuel cells, waste energy, combined heat and power, in-state versus out-of-state resources). Some states also have specific requirements or carve-outs for specific energy resources, such as solar or distributed generation. Many of these states also allow utilities to comply with their standards through the purchase of tradable renewable energy credits, though there are no national or regional markets for these credits in large part because of the significant differences among states' standards.
More than 40 states and the District of Columbia have established net metering policies that allow retail electricity consumers who own or host distributed renewable generation resources (predominantly solar electricity systems) to supply excess generation to their retail electricity supplier in exchange for credits against their retail electricity bills for periods of more than 12 months, and sometimes longer. Typically, generation resources eligible for net metering arrangements cannot be sized at levels greatly in excess of a retail consumer's peak demand. In recent years, a number of states have taken steps to revisit or revise their net metering policies in response to concerns by retail electric utilities that crediting excess generation supplied back to them at their full retail rate did not accurately reflect the costs and benefits to their other retail customers of distributed solar electric systems being interconnected to their transmission and distribution systems. Notably, while regulators in California, the state with the largest market for distributed solar electric systems, in early 2016 retained most of the existing net metering tariff for new net metering customers, they also set in motion a process to redesign residential rates for electricity, through mandatory time-of-use rates for newly installed distributed solar electric systems participating in net metering programmes, which could reduce the economic attractiveness of such systems. In other examples, regulators in Hawaii closed the state's largest electric utility's net metering programme to new participants, while regulators in Nevada approved a new net metering tariff that lowered the existing retail credit and imposed higher fixed charges, including initially for existing customers, though they later restored the prior tariff for existing customers. Similarly, legislators and regulators in some states, such as Louisiana, have enacted measures to pay the 'avoided cost' rate that is the average locational marginal price for the utility (i.e., lower than the retail rate). In 2018, Connecticut passed a law that would end net metering, only to reverse course in June 2019, providing an extension to the programme until 2021. A number of states also offer various tax incentive and rebate programmes for distributed renewable generation resources. Most notably, California provides a property tax exclusion for certain solar resources and installation cost rebates or performance-based payments for solar and certain other renewable resources (e.g., wind, fuel cells and combined heat and power).
As discussed above, many of the federal tax incentive and financing support programmes have ended, or will end no later than the end of 2021, though some of these programmes could be extended by Congress, as has been the case in the past and has been proposed in various pieces of legislation. However, given current fiscal concerns and related political disagreements about the nature and role of federal financial support for clean energy, the prospects for this type of legislation remain unclear. At the same time, state-based RPS, net metering, tax incentive and rebate programmes for distributed renewable generation resources appear poised to remain in place or be expanded in many states, at least in part, for the foreseeable future. Moreover, a number of states and local governments are actively considering establishing, and since 2011 several states and one local government, most notably the state of New York, have established, public-private partnership clean-energy financing entities, commonly referred to as green banks, to support deployment of renewable energy and energy-efficiency projects.
ii Energy efficiency and conservation
The United States has a limited set of comprehensive policies regarding promotion of energy efficiency for electric appliances and energy efficiency standards for federal buildings and properties. In addition, the federal government has various targeted grants and financing support programmes as well as tax incentives for energy efficiency investments.
A large number of states have similar types of programmes (many of which are supported in whole or in part by funds provided by the federal government) and a large number of states have energy efficiency portfolio standards, similar in concept to a renewable energy portfolio standard, that require retail electricity utilities to reduce their total retail sales, peak retail sales, or both, by certain amounts by target dates. Some states combine their renewable and energy efficiency portfolio standards. A number of states have also combined their energy efficiency portfolio standards with retail utility rate 'decoupling' policies to allow utilities recovery of and on their fixed costs regardless of reduced retail sales resulting from energy-saving efforts. Certain states have implemented, or will soon implement, financing support programmes for end-use energy efficiency investments, including 'on-bill' financing or repayment programmes that allow retail utilities or third parties to finance the full cost of end-use efficiency investments for a retail utility customer and then allow recovery of and on these investments through special charges included on the customer's retail utility bill. A similar type of financing arrangement is possible under federally authorised property-assessed clean energy (PACE) bonding authority for local governments, which use PACE bond proceeds to finance the upfront costs of energy efficiency investments in homes and small businesses and have the loans secured by an annual assessment on the home or business property tax bill, although this programme has so far generally been limited to commercial properties because of federal home mortgage insurance policies.
FERC issued Order No. 745 in 2011 to encourage demand responsiveness through market pricing mechanisms. In Order No. 745, FERC required that the ISO-organised and RTO-organised wholesale electricity markets adopt market rules that treat demand reduction (i.e., negawatts) in the same way as generation supply alternatives (i.e., megawatts (MW)) for the purpose of bidding into the markets; however, the ISOs and RTOs were still given flexibility as to how to implement these market incentives. ISOs and RTOs began proposing revisions to their market rules to FERC during 2011 to comply with Order No. 745 and FERC acted on a number of these compliance filings during 2011 and 2012. Order No. 745 was challenged before the DC Circuit on a number of grounds, including that the substance of the Order exceeds FERC's jurisdiction under the FPA, as it seeks to regulate retail sales of electricity by requiring ISOs and RTOs to pay retail customers for not consuming electricity at retail. In a decision issued in May 2014, the DC Circuit vacated Order No. 745, holding, among other things, that FERC did not have jurisdiction to issue the Order because demand response is part of the retail market, which is exclusively within the states' jurisdiction to regulate. In January 2016, the Supreme Court issued a decision upholding Order No. 745 and FERC's 'affecting' jurisdiction under the FPA to regulate demand response transactions in the organised wholesale electricity markets. The Supreme Court held that payments by ISOs and RTOs for demand response commitments directly affect wholesale rates and that in addressing demand response practices, FERC has not transgressed its jurisdictional boundary by regulating retail sales. The Supreme Court also approved a 'common-sense construction' of the FPA's language, previously adopted by the DC Circuit, that FERC's affecting jurisdiction is limited 'to rules or practices that “directly affect the [wholesale] rate”'.
The year in review
Numerous states have implemented ambitious energy policies aimed at reducing carbon emissions and increasing the amount of energy generated from renewable resources and energy storage resources on the grid. Corporate offtakers also entered into a record number of power purchase agreements with clean energy resources. Both FERC and state regulators continued to grapple with how best to accommodate advanced technologies, such as battery storage, the continuing evolution of the mix of resources that supply electric energy, capacity and ancillary services, and increased regional transmission planning. Fossil-fuelled generators again comprised nearly all retirements in 2019 and are increasingly being replaced by renewable resources despite continued attempts by the executive branch of the federal government to prevent 'baseload' generators from retiring. FERC, state regulators, grid operators and utilities also dealt with historically low wholesale electricity prices, California wildfires and California's largest investor-owned utility's bankruptcy (again).
States accelerate policies to address climate change
Since President Trump announced his intent to withdraw the United States from the Paris Agreement in 2017, states have increasingly responded with their own policies to address climate change. Hawaii had passed legislation in 2015 calling for all of its electricity to come from renewable resources by 2045. In 2018, California passed State Bill 100, which requires that 100 per cent of the electricity consumed in the state must come from carbon-free sources by 2045. In June 2019, New York passed the Climate Leadership and Protection Act, requiring a 100 per cent carbon neutral power system by 2040, and an 85 per cent reduction in GHGs by 2050. New Mexico, the District of Columbia, Maine, Nevada, Washington and Puerto Rico have also recently set 100 per cent clean energy targets. Governors in Colorado, Connecticut, Illinois, Rhode Island, Massachusetts, Minnesota, New Jersey and Wisconsin have also each committed to achieving 100 per cent carbon-free electricity, with targets for achieving that goal ranging from 2030 to 2050. These advances are indicative of the recent trend to increase RPS across the country. In 2018, 10 states increased their RPS, and in 2019, the District of Columbia, New Mexico, Nevada and Maryland increased their targets as well. In March 2020, the Virginia General Assembly passed a bill committing the commonwealth to a 100 per cent renewable energy target by 2040.
States are also innovating in their regulatory policies to promote clean energy technologies beyond setting overall targets for renewable or carbon-free electricity. For example, in January 2019, the New Hampshire Public Utilities Commission affirmed a plan to use a network of behind-the-meter batteries in homes. In June 2019, Maine enacted a law to incentivise 375MW of new distributed generation. At least five states have so far adopted targets specifically for energy storage, including New York, which has a current target to procure 3GW of energy storage capacity by 2030. Virginia's recent bill committing the commonwealth to 100 per cent renewable energy by 2040 also includes an energy storage deployment target of 2.7GW by 2035.
The NYISO and utility regulators in New York also began a process in 2017 to work with electric industry stakeholders to develop a carbon-pricing mechanism for use in the wholesale electricity markets administered by the NYISO. The NYISO issued its proposal to implement such a system in December 2018. If such a mechanism is developed, it will have to be filed with and approved by FERC before it can be implemented.
Offshore wind solicitations
Since Rhode Island's 30MW Block Island Wind Farm became the first operational offshore wind farm in the United States in 2016, there has been continued interest and investment in offshore wind in various coastal states. Since 2018, several north-eastern states created or increased their commitment to offshore wind energy. For example, the New Jersey Board of Public Utilities held a solicitation in September 2018 for 1.1GW of offshore wind generation capacity and selected a 1.1GW project in June 2019. In February 2020, New Jersey Governor Phil Murphy announced an expansion of the initiative with the goal of acquiring 7.5GW of offshore wind generation capacity by 2035. New York issued a solicitation for 800MW in November 2019. In summer 2019, New York passed a law mandating 9GW of offshore wind generation capacity by 2035. Massachusetts selected winning bidders for a solicitation for 800MW of offshore wind capacity in 2018 as well, and in August of that year passed into law an offshore wind target of 3.2GW by 2035.
The US Bureau of Ocean Energy Management, which oversees offshore renewable energy development in federal waters on the Outer Continental Shelf, completed an auction that raised US$405 million for leases covering 390,000 acres of federal waters off the coast of Massachusetts. Rhode Island has also continued its commitment to offshore wind power, announcing the winning bid to a 400MW solicitation in May 2018. Connecticut agreed to purchase 200MW of offshore wind in June 2018 and announced plans to purchase an additional 100MW in December of that year. Connecticut enacted a law requiring 2GW of offshore wind by 2030, and the state announced a deal in 2019 to develop an 800MW project. In April 2019, Maryland passed the Maryland Clean Energy Jobs Act, which requires the development of 1,200MW of offshore wind by 2030. In September 2019, Virginia's Governor called for 2.5GW of offshore wind power by 2026. California, Delaware, Hawaii, Maine, New Hampshire and North Carolina have all also expressed interest in offshore wind, with varying levels of development. There is even interest in offshore wind for inland waters, as there are current plans for offshore wind development in Lake Erie near Cleveland, Ohio.
The continued rise of energy storage
The deployment of energy storage resources in the United States nearly doubled in 2019, with approximately 523MW of energy storage capacity installed. The amount of energy storage in the United States is expected to more than double in 2020 to over 1,400 MW, and by 2021, deployments are expected to exceed 3.6GW. At least five states have now adopted specific targets for energy storage, with New York's target of 3GW by 2030 being the most ambitious to date. Other states have included energy storage in their planning processes and competitive solicitations. For example, the California Public Utilities Commission approved Pacific Gas and Electric Company's (PG&E) proposal in November 2018 to replace two retiring natural gas-fired generators with four battery energy storage projects, two of which would become the two largest in the world once placed in service. This landmark solicitation marked the first time a utility and its regulator sought to replace retiring power plants with battery energy storage systems.
To accommodate the increased implementation of electric storage resources, FERC issued Order No. 841 in 2018 and directed ISOs and RTOs to remove barriers to the participation of electric storage resources in the organised wholesale electricity markets by requiring the ISOs and RTOs to establish market rules that facilitate the participation and take into account the physical and operational characteristics of electric storage resources. All six ISOs and RTOs, other than ERCOT, filed implementation plans with FERC in 2019 to comply. Order No. 841 is currently subject to appeal from some state PUCs and certain utilities who argue, in part, that (1) FERC does not have the authority to set terms and conditions for energy storage resources located behind-the-meter or interconnected to local distribution facilities, (2) FERC's decision to not permit states to opt out of Order No. 841 was arbitrary in light of FERC affording states such a carve-out regarding demand response participation in wholesale markets, and (3) the order violates the 10th Amendment to the US Constitution.
Fossil-fuelled generator retirements
Since the beginning of 2015, approximately 47GW coal-fired capacity has retired, with effectively no new coal capacity coming online. An estimated 4.1GW of coal capacity retired in 2019, accounting for more than half of all anticipated power plant retirements for the year. In 2007, coal-fired generation capacity totalled 313GW across 1,470 generators. In the subsequent 10 years, 529 of those coal-fired generators, with a total capacity of 55GW, retired, and that trend continued in 2018 and 2019. Projections for 2020 show scheduled capacity retirements of 11GW, which will primarily be driven by coal (51 per cent), followed by (mostly older) natural gas (33 per cent) and nuclear (14 per cent) generating resources. An estimated 42GW of new capacity additions will start commercial operation in 2020, with solar and wind representing the vast majority of additional capacity, at 18.5GW and 13.5GW, respectively. New natural gas generation is expected to add an additional 9.3GW of capacity in 2020.
In August 2017, in response to a request from the Secretary of Energy, the staff of DOE issued a study regarding the wholesale electricity markets and grid reliability in which they found that the wholesale markets, especially the organised markets administered by ISOs and RTOs, are operating in a manner that may result in the premature retirement of baseload coal-fired and nuclear generation facilities that may be needed to ensure the reliability and the resiliency of the bulk power grid. In turn, in September 2017, the Secretary of Energy acted under little-used authority under the DOE Organization Act to submit a proposed rule at FERC that directed FERC to consider requiring certain ISOs and RTOs to establish tariff mechanisms providing for the purchase of energy from generation resources and the recovery of costs and a return on equity for the resources located in an ISO or RTO with an energy and capacity market that are able to provide essential reliability resources and that have a 90-day fuel supply on-site. In the FERC proceeding to address the Secretary's proposed rule, a large number of parties submitted comments opposing the proposed rule (including an ad hoc bipartisan group of former FERC chairs). In early January 2018, FERC, with the unanimous vote of all five of its commissioners, issued an order terminating its proceeding to address the proposed rule and initiated a new proceeding to evaluate the resilience of the bulk power grid in the footprints of the ISOs and RTOs, which remains pending. The Trump administration has since continued to evaluate other proposals to keep certain baseload plants in service that may otherwise face retirement.
Capacity markets and state-subsidised generation resources
FERC has explored how states' preferences for certain generation resources have affected capacity markets since as early as 2013 when it opened a proceeding to explore the topic. Since then, both ISO-New England and PJM have developed their own proposals to address the competitive effects of states subsidising certain resources with mixed results. In March 2018, FERC approved ISO-New England's proposed change to its capacity market rules, referred to as the Competitive Auctions with Sponsored Policy Resources, which provides for a new two-stage capacity auction in which existing capacity resources that clear the first-stage auction and have resulting capacity obligations can transfer their capacity obligations to new sponsored policy resources that did not clear the first-stage auction in a second-stage substitution auction and permanently exit the capacity market. The order, however, approved the changes by a divided vote of the five FERC commissioners with two dissenting votes and a concurrence.
After failing to reach a consensus among its stakeholders, PJM submitted two options to FERC in April 2018 and requested that FERC pick one of them. The first option, the capacity repricing proposal preferred by PJM, would create a second stage of the capacity auction where bids received from subsidised resources would be repriced without the resource's subsidy to create the resource's competitive price. The second option, referred to as MOPR-Ex, would have expanded PJM's existing minimum offer price rule (MOPR) to new and existing resources that received subsidies, with some exceptions. In June 2018, FERC issued an order responding not only to PJM's proposals but also to a complaint filed by a group of power producers in 2016 that also sought an expansion of PJM's MOPR to existing generators that were receiving state subsidies. Rather than accept either of PJM's proposals, FERC rejected both as inadequate with respect to addressing the competitive effects of state-subsidised resources on its capacity market and went further by finding PJM's existing capacity market framework to be unjust and unreasonable. FERC also found, however, that it could not make a determination as to what would be an acceptable replacement based on the record before it and instead instituted a paper hearing for parties to submit additional arguments and evidence regarding what the replacement should be. FERC did preliminarily find that modifying two aspects of the PJM capacity market may provide for an acceptable replacement, namely expanding the MOPR to new and existing subsidised generators with few or no exceptions and also implementing a resource-specific fixed resource requirement alternative whereby a subsidised resource could choose to be removed from the capacity market, along with a corresponding amount of load, but continue to participate in PJM's energy and ancillary services markets so as to accommodate state-sponsored resources without requiring load-serving entities to pay for capacity twice. Hundreds of filings were submitted in these proceedings and in December 2019, FERC, based on the determination that out-of-market payments provided by states to support operation of certain generation resources threaten the competitiveness of PJM's capacity market, directed PJM to expand the MOPR to apply to any new or existing resource that receives, or is entitled to receive, a state subsidy (with some exceptions). Application of a MOPR to a resource's market bid makes it less likely that the resource will be awarded a capacity supply obligation and therefore receive capacity payments. In the December 2019 order, FERC outlined certain exemptions from the expanded MOPR, including (1) existing renewable resources that are participating in state renewable portfolio programmes, (2) existing demand response, energy efficiency and storage resources, (3) existing self-supply resources and (4) competitive resources that do not receive state subsidies. In its compliance filing submitted in March 2020, PJM expanded on the list of state subsidies that will not trigger application of the MOPR and indicated that it would work with the internal market monitor for PJM and resource owners to maintain that list. PJM also proposed a compressed schedule to complete its delayed capacity auctions. The proposal remains subject to ongoing litigation at FERC and, ultimately, an order from the Commission.
An increased focus on cybersecurity in the energy sector has materialised after several high-profile intrusions affected multiple companies with nuclear power plants in the United States in 2017. As noted in Section III.iii, NERC is the nation's ERO in charge of developing and enforcing reliability standards for the bulk power grid, including Critical Infrastructure Protection (CIP) standards that address physical and cybersecurity. On 25 January 2019, NERC published a notice of penalty to an unnamed utility for a record-high total of US$10 million after citing some 127 violations of reliability and security standards between 2015 and 2018. Violations of CIP standards were the most frequently violated. NERC also issued a US$2.7 million fine, on 31 May 2018, on one utility that reportedly left user names, passwords and grid information unsecured. As more grid resources have become decentralised, NERC has increased its focus on supporting the security of supply chains and is working with utilities to ensure the security of information and communications technology as well as industrial control system equipment. NERC is now considering expanding its existing CIP standards, which already require entities possessing medium- and high-impact cyber systems to ensure supply chain risks are being managed through the procurement process, to include supply chain risks associated with additional categories of assets not currently subject to existing supply chain standards.
Judicial review of FERC enforcement cases
FERC has substantial civil penalty authority under the FPA, including the ability to issue civil penalties in excess of US$1 million per violation per day in addition to requiring disgorgement of ill-gotten gains. In the event that FERC finds an entity liable, under the FPA the entity has the ability to force FERC to litigate the matter in federal district court. There has been substantial litigation regarding the scope of the district court's review of FERC's findings, with FERC arguing that the district court's review should be limited to FERC's findings based on the administrative record created by FERC (i.e., akin to an appellate type of review). District courts, however, have repeatedly and unanimously ruled against FERC, holding that they are to conduct a trial de novo, governed by the Federal Rules of Civil Procedure and the Federal Rules of Evidence. In February 2020, the US Court of Appeals for the Fourth Circuit issued a decision regarding the statute of limitations for certain FERC enforcement cases. The FPA creates two procedural options by which FERC can assess civil penalties: (1) after a hearing before a FERC administrative law judge; or (2) after adjudication in federal district court. The Fourth Circuit ruled that the statute of limitations period commences on the date the alleged violator chooses to pursue its claims federal district court (if it chooses that route). The ruling effectively allows FERC to investigate past alleged unlawful conduct without time limitation.
The continuing transformation of the public utility business model
Several states have continued efforts to consider the restructuring or transformation of the distribution and use of electricity at the retail level, including efforts to accommodate or encourage the greater deployment of distributed energy resources – distributed generation and storage, demand response and end-use energy efficiency. Most notably, regulators in New York have continued their efforts to implement their Reforming the Energy Vision (REV) initiative, which calls for 'animating markets' at the distribution level so that retail customers and third parties (e.g., energy service companies, retail suppliers and demand-management companies) can monetise the economic values that distributed resources can provide to the overall electricity system in New York. This initiative also tasks the electricity distribution utilities in New York with acting as 'distributed system platform' providers, who together will furnish a state-wide platform that will deliver uniform market access to retail customers and distributed energy resource providers, and who will also act as an interface between customers at the distribution level and the NYISO. As part of this initiative, regulators also directed the electricity distribution utilities to propose demonstration projects involving third-party market participants and demonstrating business models and customer engagement for distributed energy resources and to propose a Distributed System Implementation Plan.
In a series of proceedings, regulators in New York have implemented rules on a wide range of issues relating to the REV initiative, including a new benefit–cost framework for electricity distribution utility expenditures on investments in distributed system platforms, procurement of a 'value stack' compensation model for distributed energy resources, energy efficiency programmes, development of community distributed generation and CCA arrangements, changes in net metering programmes, a reassessment of New York's approach in encouraging the deployment of large-scale renewable energy generation, and the development of a US$5 billion Clean Energy Fund that will in part support the New York Green Bank and a solar electric incentive programme. New York has adopted a goal of having 70 per cent of the electricity consumed in New York to come from clean energy sources by 2030 and an 85 per cent reduction in GHG emissions by 2050. Relatedly and as discussed in Section V, New York's governor has committed to achieving 100 per cent carbon-free electricity in the state by 2040. Regulators have indicated that changes in their rate-making practices for electricity distribution utilities should result in utility earnings that depend on a utility's success in creating value for its customers and achieving regulatory policy goals, such as increased deployment of distributed energy resources and reduced emissions of GHGs, and they issued an order in 2016 adopting a suite of rate-making changes for electricity distribution utilities, including providing them with the ability to earn revenues from:
- the achievement of alternatives that reduce their capital spending and provide definitive consumer benefits;
- market-facing platform activities; and
- transitional outcome-based performance measures.
Zero emission credit and coal encouragement programmes
Regulators in New York have also established a zero emission credit (ZEC) compensation mechanism to subsidise the continued operation of certain existing nuclear generation facilities in New York that face competitive difficulties in the NYISO markets, concluding that the continued operation of these facilities is necessary for New York to achieve its clean energy policy goals. Legislators in Illinois established a somewhat similar ZEC compensation mechanism directed at certain existing nuclear generation facilities in the state that face competitive difficulties in the PJM and MISO markets. Both the New York and Illinois programmes take into consideration the revenues that existing nuclear facilities receive in the energy and capacity markets in the determination of the ZEC payment. Legislators in New Jersey have established a similar ZEC compensation mechanism for existing nuclear generation facilities in New Jersey. Both the New York and Illinois programmes were subsequently challenged in federal courts on constitutional grounds relating to federal pre-emption under the FPA and as being in violation of the dormant commerce clause and before FERC on grounds relating to the continuing lawfulness under the FPA of forward capacity market rules in the NYISO and PJM.
In 2018, the US Courts of Appeals for the Second and Seventh Circuits upheld the ZEC programmes in New York and Illinois, respectively. In Electric Power Supply Association v. Star, the Seventh Circuit held that the Illinois nuclear subsidy programme was not pre-empted by federal law because it does not require the subsidised generation to participate in the FERC regulated markets. While the Seventh Circuit found that the Illinois programme 'can influence the auction price only indirectly', the court held that 'because states retain authority over power generation, a state policy that affects price only by increasing the quantity of power available for sale is not preempted by federal law'. In Coalition for Competitive Electricity v. Zibelman, the Second Circuit noted that the plaintiffs conceded that the New York nuclear subsidy programme did 'not expressly mandate that the plants receiving ZEC subsidies bid into the NYISO auctions'. The Second Circuit also held that any distortions to the wholesale market are '(at best) an incidental effect resulting from New York's regulation of producers'. Accordingly, the Court held that the 'Plaintiffs have failed to state a plausible claim for conflict preemption'. The Supreme Court of the United States issued orders in April 2019 denying petitions for review of the Second and Seventh Circuits' decisions.
In addition, states have also moved to provide subsidies and incentives to other traditional generating resources. In July 2019, Ohio enacted a law designed to subsidise two large nuclear energy plants owned by FirstEnergy Solutions Corporation, and to provide ratepayer-backed funding for two coal-fired plants operated by Ohio Valley Electric Corporation. In March 2020, the Indiana legislature passed a bill that was subsequently signed into law by the governor that could slow the retirement of any legacy generation plant owned by a public utility exceeding 80MW in capacity by requiring several months' prior notification to, and review by, the Indiana Utility Regulatory Commission. Similarly, in March 2020, West Virginia enacted a law that would reduce the tax rate on coal-fired generating units in service before 1995 that agree to stay online until 1 July 2025 to 45 per cent of their official capacity.
Green tariffs and corporate power purchases
Green tariffs are programmes offered by utilities, typically in states without retail choice, that allow larger commercial and industrial customers to buy both the energy from a renewable energy project and the environmental benefit from such generation (e.g., renewable energy certificates) in a long-term, fixed price structure. These programmes help corporate entities in states without retail choice programmes to meet their sustainability goals. Since the first green tariff was proposed by NV Energy in Nevada in 2013, 23 green tariffs in 17 states have been proposed or approved, with two denied by the relevant state public utility commission. In 2018, Kansas, Kentucky, Minnesota and Virginia each adopted green tariff programmes.
These programmes vary in their implementation. Some allow customers to choose market-based rates pegged to the wholesale price, while others let organisations engage directly with the renewable power project. Further still, some programmes use a 'sleeved' power purchase agreement, whereby the utility passes a physical power purchase agreement that it has signed with a renewable energy project to the consumer. Green tariffs are now being used in particular by a number of larger information technology firms, including Apple, which purchases from NV Energy's GreenEnergy Rider programme, and Google, which uses Duke Energy's green tariff.
It has been another record year for corporate clean energy contracts, which accounted for 19.5GW, up from 6.53GW in 2018. Many companies have aggressive clean energy goals. For example, Visa committed in 2018 to 100 per cent renewable energy by the end of 2019, and Sony expanded its 100 per cent renewable goals to China and North America.
California faced historically destructive wildfires in 2017 and 2018, with more than 8,000 wildfires burning approximately 1.8 million acres in 2018 alone. Facing liability from these fires, California's largest investor-owned utility, PG&E, filed for Chapter 11 bankruptcy on 29 January 2019. On 28 February 2019, PG&E announced it would record a US$10.5 billion charge related to third-party claims in connection to the Camp Fire in its full year and fourth quarter 2018 financial reports, and an additional US$1 billion pre-tax charge related to 2017 wildfires. In March 2020, a court approved a US$23 billion plan under which PG&E would emerge from bankruptcy by June. California had made PG&E's ability to access a state wildfire insurance fund contingent upon the company exiting bankruptcy by the end of June. PG&E previously entered bankruptcy in 2001 following the California energy crisis.
The PG&E bankruptcy also raises jurisdictional questions between the bankruptcy court and FERC relating to the ability of PG&E as a debtor in bankruptcy to reject FERC-jurisdictional wholesale power contracts, an ability that debtors have under the federal Bankruptcy Code with regard to executory contracts. In January 2019, FERC issued a declaratory order asserting that it has concurrent jurisdiction with the bankruptcy court regarding the disposition of these types of contracts, such that PG&E would need to obtain approval from both FERC, under its applicable standard of review, and the bankruptcy court, under its applicable standard of review, to reject such an agreement. In the bankruptcy court, PG&E sought and was granted a preliminary injunction against FERC to prevent it from exercising its asserted concurrent jurisdiction. The injunction proceeding has been appealed to the Ninth Circuit Court of Appeals. California regulators have also asserted that the California Public Utilities Commission's permission would be needed by PG&E to avoid contractual commitments with clean energy resources or else it would interfere with the state's clean energy goals, and have considered splitting up PG&E's natural gas and electric divisions into separate companies. The bankruptcy proceeding remains pending and is expected to continue for at least two years.
In a similar proceeding, the Sixth Circuit Court of Appeals found that bankruptcy courts do have jurisdiction over FERC-approved contracts.
ii Natural gas and hydrocarbon liquids pipelines, LNG terminals and rail transportation of crude oil
As gas production in the United States has grown dramatically in recent years, the interstate pipeline industry has constructed, with FERC's approval, large amounts of new infrastructure to serve the new production and transport the gas to markets. FERC's approval of large new pipeline projects essentially peaked in 2017, with fewer projects since then. The number of pipeline projects characterised by FERC as 'major' that have been issued certificates of public convenience and necessity was 36 in 2016, 35 in 2017, 29 in 2018 and 23 in 2019. Looking only at the pipelines with capacity of more than 1 billion cubic feet per day, FERC certificated six in 2016, nine in 2017, two in 2018 and six in 2019. And for pipelines more than 100 miles long, FERC certificated three in 2016, seven in 2017, two in 2018 and two in 2019. The largest pipelines certificated in 2019 were all approved in conjunction with LNG export projects, including six of the 'major' pipelines, all six of the pipelines with capacity of more than 1 billion cubic feet per day, and both of the pipelines that are more than 100 miles long.
Recent litigation regarding FERC permitting pipelines and LNG facilities
Pipeline certificate proceedings have increasingly become heavily contested, with significant opposition to many projects from certain environmentalist organisations and landowners. Decisions regarding many of the recent pipeline certificates have also led to divisions among the FERC commissioners, with the Republican commissioners (who have been a majority since 2017) generally approving project proposals and Democratic commissioners often submitting dissenting or concurring opinions raising concerns about a project, usually regarding environmental impacts (especially about GHGs) but also about the need for the projects.
The increased opposition to pipeline projects has also led to frequent appeals of both FERC's certificate orders and related decisions by other agencies issuing required environmental permits for the projects. Some of the most important recent appellate decisions concerning pipeline projects are summarised below.
In June 2014, the DC Circuit ruled that the FERC had violated the National Environmental Policy Act of 1970 (NEPA) by improperly segmenting its review of four proposed expansions of the pipeline system of Tennessee Gas Pipeline Company in the North-East. FERC regarded the proposed expansions as four separate projects because each resulted in a measurable increase in the pipeline's overall capacity and therefore provided substantial independent utility. The proposed projects were reviewed individually by the FERC and then constructed in rapid succession between 2010 and 2013. The DC Circuit found that the projects were 'physically, functionally, and financially connected and interdependent' and should all have been reviewed by the FERC at the same time as connected projects under NEPA, and that the FERC should have considered the cumulative impacts of all four projects before approving any one of them. The DC Circuit remanded the case to FERC, which involved one of the already built and operating segments, but it did not vacate FERC's order. This decision allowed the pipeline segment to continue to operate while FERC supplemented its environmental analysis. On remand, FERC conducted a supplementary environmental review and reaffirmed its approval of the challenged pipeline project. The DC Circuit's decision is significant in three respects: (1) although challenged many times, FERC had not previously lost an appeal of a natural gas pipeline case under NEPA; (2) the decision creates uncertainty as to when proposed pipeline projects must be reviewed together, as many proposed projects affect other proposed projects; and (3) the court allowed the pipeline to operate despite its finding that FERC had violated NEPA.
In August 2017, the DC Circuit vacated and remanded FERC's orders approving the Southeast Market Pipelines project for failure to evaluate the effects of downstream GHG emissions associated with non-jurisdictional power plants receiving fuel from the project, or to explain why it could not do so. FERC reapproved the project after providing a supplementary analysis, including disclosure of an upper estimate of emissions from the power plants, but without assessing those impacts using the social cost of carbon tool – two of the five FERC commissioners dissented. In subsequent pipeline certificate proceedings, the extent to which FERC needs to consider GHG emissions associated with upstream production and downstream consumption of natural gas has frequently been a contested issue.
A number of state regulators responsible for issuing water quality determinations under the federal Clean Water Act withheld or denied certifications for FERC pipeline projects, leading to litigation in a number of courts. The leading case involved a New York State water quality certification for Millennium Pipeline's Valley Lateral pipeline. After New York State failed to act within the one-year time frame set by the statute, the project obtained a ruling from FERC in 2017 finding that the state waived its certification authority under that statute. New York appealed to the Second Circuit arguing that it had one year from the date a 'complete' application is filed to act, while FERC countered that the one-year period begins when the application is initially filed. The Second Circuit sided with FERC.
In a more recent case involving the Constitution Pipeline proposed to be constructed in Pennsylvania and New York, the Second Circuit declined to decide a challenge to New York's failure to issue a water quality determination under the Clean Water Act, instead requiring that the pipeline first seek a waiver from FERC. FERC initially denied the pipeline's waiver request because the New York agency had acted within one year of receipt of the most recently filed application, after the initial application was voluntarily withdrawn and resubmitted by the pipeline. In 2019, however, FERC reversed itself and ruled (in a 2-1 decision) that the New York agency had waived its authority under the Clean Water Act, holding that the pipeline withdrawals and resubmissions of its application did not extend the one-year period for state action or waiver. Notwithstanding, FERC's finding that the New York agency had waived its authority under the Clean Water Act, the Constitution Pipeline project was cancelled in early 2020. Other FERC-approved natural gas pipelines continue to face judicial challenges to administratively issued environmental permits that continue to delay construction, including the two largest pipeline projects approved by FERC in 2017, namely the Atlantic Coast Pipeline and Mountain Valley Pipeline.
One of the largest pipelines certificated by FERC in 2018, the PennEast Pipeline, has faced a different kind of permitting challenge. In September 2019, the Court of Appeals for the Third Circuit agreed with New Jersey that the power of eminent domain conveyed with an NGA certificate does not provide authority to seize or condemn state lands, including both state-owned land and land where the state has non-possessory property rights under conservation easements and restrictive covenants. In response, PennEast filed a petition for declaratory order with FERC, which FERC granted in early 2020. FERC (in another 2-1 decision) held based on statutory interpretation and legislative history that certificates do allow for condemnation of property in which a state owns an interest, adding an explanation asserting that the Third Circuit's decision would have profoundly adverse effects on the development of the interstate pipeline system and significantly undermine how the industry has operated for decades. While FERC's ruling does not alter the Third Circuit's decision, PennEast is utilising FERC's ruling to try to obtain review of that decision by the Supreme Court of the United States.
Oil pipeline rates
FERC has continued to allow more flexibility with respect to rates, terms and conditions of service for committed shippers on new and expanded oil pipeline capacity when that capacity is offered to all potential shippers in an open season process. Among other approvals, FERC has allowed committed shippers to negotiate rates not supported by cost of service, and to give priority to future available capacity and future expansion projects following the open season. FERC has also approved tiered rates for shippers based on the size of their volume commitments and acreage dedications. Other FERC orders have defined the limits of oil pipelines' rate flexibility, including orders denying priority service to shippers that enter into contracts after (but not during) an open season, and orders refusing to pre-approve uncommitted shipper rates for new and expanded oil pipelines unless pursuant to a formal rate filing made shortly before service commences. In 2015, FERC also determined that the transportation by pipeline of denatured fuel ethanol in interstate commerce is subject to its jurisdiction. In 2019, FERC ruled that an oil pipeline's initial rates for new service cannot be treated as settlement rates even if shippers agree to those rates. Instead, the pipeline must justify initial rates by providing either (1) cost-of-service support for the rates or (2) an affidavit that a non-affiliated shipper that intends to use the service agrees to the rates.
A court decision in July 2016 has had broad implications for the interstate pipeline industry. In United Airlines v. FERC,3 the DC Circuit sided with pipeline shippers that challenged FERC's income tax allowance policy, which had been in place since 2005. That policy allowed US MLPs and other pass-through entities that hold interests in regulated oil and natural gas pipelines to include in rates an income tax allowance if their partners or members have actual or potential income tax obligations on the partnership's or other pass-through entity's income. In United Airlines, the DC Circuit held that the Commission failed to demonstrate that there was no double recovery of income tax costs when permitting SFPP, LP (SFPP), a wholly owned subsidiary of an MLP, to recover both an income tax allowance and an ROE using the DCF methodology. The Court observed that an income tax allowance would provide SFPP revenues for entity-level, corporate taxes that SFPP does not pay, and that SFPP's investors already recover their income taxes through the DCF-determined ROE. Given this apparent double recovery of income taxes, the Court vacated FERC's orders and remanded the case for further proceedings.
After accepting additional evidence and arguments from interested parties, FERC issued two orders on remand in March 2018. In those orders, FERC found that permitting an MLP pipeline to recover both an income tax allowance and a DCR-determined ROE results in a double recovery of investors' tax costs.4 Accordingly, the Commission announced that generally it will not permit MLPs to include an income tax allowance in their cost-of-service rates. On rehearing of the Revised Policy Statement5 and in a related case, SFPP, LP,6 the Commission held that MLPs that no longer include an income tax allowance in their rates can 'zero out' their accumulated deferred income tax balances without refunding those amounts to ratepayers. These orders are now on review in the DC Circuit.7 In the meantime, FERC has announced that other pass-through entities may be allowed to recover the income tax allowance in cost-based rates but only if they successfully address the double-recovery concern expressed in United Airlines and the Revised Policy Statement.
In March 2018, FERC also issued orders initiating a rule-making and a notice of inquiry to evaluate whether the reduction of the federal corporate tax rate from 35 per cent to 21 per cent should be reflected in individual oil and natural gas pipelines' cost-based rates or require other changes to pipeline rates. In July 2018, FERC issued a final rule (Order No. 849) that required gas pipelines to submit informational reports showing the impact of lower corporate tax rates and the disallowance of taxes for MLPs in their cost-based rates. FERC's orders encouraged gas pipelines either to reduce their rates voluntarily by initiating limited, single issue rate proceedings, or to provide justification why their rates should not be reduced. FERC reserved the right to investigate potential over-recovery by gas pipelines that did not voluntarily reduce their rates. FERC also clarified that a pipeline organised as a pass-through entity is considered subject to federal corporate income tax (and thus may include an income tax allowance in rates) if all its income or losses are consolidated on the federal income tax return of a corporate parent. In compliance with the rule, gas pipelines filed the informational reports. Some pipelines voluntarily reduced rates as part of negotiated settlements with customers, and FERC initiated investigations into the reasonableness of certain pipeline rates after concluding that the pipelines might be substantially over-recovering their cost of service. In most cases, however, FERC elected not to take any action regarding pipelines that did not modify their rates.
In the March 2018 orders, FERC also announced that oil pipeline rates will be reduced to reflect lower income tax rates prospectively in FERC's next round of five-year rate-indexing adjustments in 2020, to be effective as of 1 July 2021. In the interim, liquids pipeline shippers may file complaints if they believe the pipelines' rates are unreasonable, and liquids pipelines that initiate rate changes must comply with the lower corporate income tax rates and new rule applicable to pipelines organised as flow-through entities.
LNG export terminals
Between 2013 and 2017, FERC approved the construction and operation of 10 large-scale LNG terminals, nine for the export of LNG produced from natural gas originating in the continental United States and one for the import of LNG to the Commonwealth of Puerto Rico. Six of the LNG export projects (five of which were existing LNG import facilities that added liquefaction for export purposes) are in at least partial operation as of early 2020.
In 2019, FERC authorised a large second wave of LNG export projects. In February 2019, FERC authorised the Venture Global Calcasieu Pass Project, its first new LNG export project in more than two years. During the rest of 2019, FERC authorised 10 more LNG projects, plus another in early 2020, acting on almost all the proposed second wave projects (leaving only the very large Alaska LNG project which remained pending at FERC). All the LNG project authorisation orders include numerous conditions and require close FERC supervision of construction activities. Certain of the FERC authorisation orders have been challenged on appeal.
While the second wave of LNG export projects have received FERC approvals (as well as export authorisations from DOE, as discussed below), they continue to face the interrelated challenges of obtaining binding agreements with customers and financing. Just two LNG export projects reached positive financial investment decisions in 2019 and are engaged in significant construction activity under FERC oversight: the Calcasieu Pass Project and Golden Pass, which was authorised by FERC in 2017.
Several of the initial round of FERC orders approving LNG export projects were appealed to the DC Circuit by the Sierra Club and similar non-government environmental organisations. These appeals concerned both project-specific issues and common issues regarding FERC's NEPA review as related to more general, indirect and cumulative environmental effects. Among the common issues were claims that approval of new LNG terminals will induce additional US natural gas production for export, thereby increasing demand for natural gas and increasing its price in the United States, resulting in the increased use of coal rather than natural gas to generate electricity. These groups also asserted that approval of LNG exports would contribute to increased GHG emissions from downstream end use of natural gas. In a series of separate opinions issued by the DC Circuit during the latter half of 2016, the Court affirmed FERC's orders approving four large-scale LNG terminals, holding that the environmental review did not have to address the alleged indirect and cumulative effects of the LNG exports in upstream and downstream markets, in part because DOE has sole authority to authorise the export of natural gas and LNG. The DC Circuit also held that FERC adequately considered the environmental effects of the LNG terminals, together with any other past, present or likely future actions in the same geographical area.
In 2016, FERC denied applications to construct the Jordan Cove LNG export terminal in south-west Oregon and the related Pacific Connector Pipeline. FERC found that the proponents of the Pacific Connector Pipeline had presented only general evidence as to natural gas demand in an effort to prove a need for the pipeline, but no evidence of subscriptions for its services. The project's proponents filed a new application in September 2017 with supplementary evidence demonstrating market support for the pipeline. In March 2020, FERC approved the new application to construct and operate, with the Pacific Connector pipeline to connect to the terminal, finding them not inconsistent with the public interest. Shortly before FERC's approval, the Oregon Department of Land Conservation and Development (DLCD) denied the project applicants' request for a state-issued coastal zone permit under the federal Coastal Zone Management Act (CZMA). The applicants have appealed the DLCD's ruling to the Secretary of the US Department of Commerce (who oversees certain aspects of states' administration of the CZMA), asking that the Secretary override the DLCD ruling under the Secretary's authority under the CZMA.
In August 2014, DOE announced a change in its policy regarding the processing of export applications to streamline its process by linking the timing of its final action on an application to follow the completion of environmental reports by FERC and other agencies. DOE also issued reports supplementing the environmental analysis of LNG export terminals, including an analysis of the effect of LNG exports on GHG emissions and a new study of the estimated economic consequences of LNG exports (up to the equivalent of 20 billion cubic feet of natural gas per day or approximately 168 million tonnes per year), which found that the additional exports would be marginally beneficial to the US economy.
In September 2014, DOE issued a notice of change in its procedures for changes in control affecting applications and authorisations to export or import natural gas. The new procedures allow for authorisation holders to file a notice or statement of a change in control within 30 days of such a change in control. DOE will consider properly submitted protests of changes in control relating to existing authorisations or pending applications for authorisations to export to countries with no free trade agreement (FTA), but will take no action unless it determines that the change in control renders the underlying authorisation at issue inconsistent with the public interest.
Under that policy, DOE has consistently authorised LNG projects, after they receive FERC authorisation for construction and operation, to export LNG to all countries not specifically prohibited from receiving LNG from the United States (i.e., countries not subject to US trade sanctions), including countries without FTAs to which the United States is a party, that require national treatment for trade in natural gas (non-FTA countries). DOE issued a non-FTA export authorisation in April 2017 that followed its prior precedent, indicating that there was no change in policy with the new administration. Later in 2017, DOE commissioned a new macroeconomic study of the effects of LNG exports. The study was issued for public comment in June 2018 and DOE responded to those comments in December 2018. Like the prior DOE studies of the issue, the 2018 study concluded that the United States will experience net economic benefits from LNG exports.
Relying in part on this study, DOE authorised LNG exports to non-FTA nations for all the LNG export projects authorised by FERC in 2019. In each instance, DOE issued the export authorisation promptly following issuance of the FERC action, taking longer only when FERC issued numerous approvals around the same time. All DOE export authorisations are very similar, with its analysis focused largely on the general benefits of LNG exports with relatively little analysis of the merits of specific project factors.
Environmental groups have filed challenges to many of the DOE's orders authorising exports of LNG (similar to those lodged against FERC's orders) in the DC Circuit. In a series of orders issued in 2017, the DC Circuit rejected all arguments that DOE failed to adequately consider the cumulative and indirect effects associated with induced upstream gas production and downstream GHG emissions. The DC Circuit held that DOE's 'environmental addendum' and a life cycle analysis assessing currently available data (filed and noticed for public comment in each proceeding) was a sufficient assessment of the environmental effects of DOE's orders. The effect of these appellate decisions in the LNG and Southeast Market Pipelines proceedings is to increase overall transparency associated with natural gas sector GHG emissions, but perhaps not to the extent desired by some advocates who prefer use of the social cost of carbon tool for measuring the impact of increased GHG emissions. The orders serve as precedent for future FERC and DOE actions approving natural gas facilities and exports.
In June 2018, DOE issued a final rule to provide for accelerated approval of applications for small-scale exports of natural gas, including LNG, from export facilities to non-FTA countries. The final rule provides that DOE, upon receipt of a complete export application, will grant the application if (1) the application proposes the export of no more than 51.75 billion cubic feet of natural gas per year, and (2) the proposed export qualifies for a categorical exclusion under DOE's NEPA regulations.
Presidential permits for cross-boundary energy facilities
Presidential permits are required for the construction and operation of energy facilities that cross the international borders with Canada and Mexico, including facilities for the transmission or transportation of electricity, natural gas, crude oil and petroleum products. The authority to issue Presidential Permits has been delegated by the President to the Secretary of Energy for electricity, to FERC for natural gas and to the Secretary of State for crude oil and petroleum products. Historically, there has been little controversy about the issuance of presidential permits, and more than 100 cross-border energy facilities were in operation as of 2017. FERC and the Secretary of Energy, acting through DOE, have continued to receive and, after consultation with the Secretary of Defense and the Secretary of State, approve presidential permits for natural gas and electricity facilities in the ordinary course.
In contrast, the presidential permit process for the Keystone XL pipeline has been the subject of protracted litigation. This pipeline is intended to transport heavy crude oil and diluted bitumen produced from Western Canadian oil sands, and light crude oil produced in the Bakken shale formation in the United States, to refineries on the US Gulf Coast. An application for a permit was filed with the Department of State in May 2012. After several years of deliberation by the Department of State and relevant federal agencies, and an attempt by Congress to get involved in the approval process, the Obama administration's State Department denied the application in November 2016. After the Trump administration took office, the Department of State reversed course and issued a presidential permit in March 2017. In November 2018, however, the US District Court for the District of Montana found that a supplementary environmental review from the Department of State was required, and placed an injunction on pipeline construction. In March 2019, President Trump revoked the prior presidential permit and issued a new one. Nevertheless, in April 2019, a new lawsuit was filed in the District of Montana challenging the new permit. The complaint asserts that the new permit is invalid because it purports to grant permission to construct the pipeline over portions of federal land that are properly under the jurisdiction of the Bureau of Land Management, does not contain a finding that the President's authorisation was in the national interest, does not include a fact-based explanation of the decision to grant the authorisation, and grants authorisation without requiring compliance with federal environmental and procedural laws. On 15 April 2020, the US District Court for the District of Montana granted in part the plaintiffs' motion for partial summary judgment in ruling that the US Army Corps of Engineers' 2017 reauthorisation of Nationwide Permit 12 (NWP 12) violated the Endangered Species Act because the Army Corps failed to complete a programmatic consultation with the US Fish and Wildlife Service and the National Marine Fisheries Service regarding the environmental effects of the reauthorisation. At the time of writing, further litigation is anticipated regarding the District Court's ruling on NWP 12.
Keystone XL has received several state and local approvals for the portion of the pipeline located in the United States, including from state regulators in Montana and South Dakota. The Nebraska Public Service Commission's approval, which was initially granted in 2017 and required the pipeline to use an alternative route in the state, was ultimately upheld by the Nebraska Supreme Court in August 2019. However, Keystone XL has yet to receive all its necessary county-level approvals in Nebraska. In addition, Keystone XL has filed numerous condemnation claims in Nebraska, some of which have been challenged in state court by landowners.
Rules on transporting crude oil and LNG by rail
In response to a series of highly publicised accidents involving trains carrying crude oil produced from the Bakken Formation, including the July 2013 derailment of a 72-car train carrying Bakken crude oil that resulted in 47 fatalities and extensive property damage in Lac-Mégantic, Quebec, US federal and state regulators have taken numerous steps to improve the safety of the rail transportation of crude oil. The North Dakota Industrial Commission issued new conditioning standards in December 2014 that established, among other matters, operating standards for crude oil conditioning equipment and prohibited operators from blending lighter hydrocarbons into crude oil before shipment. The PHMSA and the Federal Railroad Administration (FRA) have proposed or undertaken a range of additional regulatory actions aimed at increasing the safety of rail transportation of hazardous materials, including crude oil. The PHMSA and FRA issued a comprehensive final rule in May 2015 that includes more stringent construction standards for rail tank cars built after 1 October 2015. Depending on their type, existing tank cars must be replaced or retrofitted within three or five years. The final PHMSA/FRA rule also includes mandates for using advanced braking and performing routing analyses, and makes permanent the provisions of an emergency order issued by the Department of Transportation (DOT) in April 2015 imposing a speed limit of 40mph in high-threat urban areas for crude oil trains containing at least one older-model tank car. The speed limit for all other crude-by-rail service will be restricted to 50mph, in line with the speed limit rail companies voluntarily adopted in 2013. The final rule requires sampling and testing programmes for all unrefined petroleum-based products, including crude oil, and certifications that hazardous materials subject to the programme are packaged in accordance with the test results, but does not require oil companies to process their products to make them less volatile before shipment, as had been proposed by certain safety advocates. Further rules were proposed in October 2019 that would permit the bulk transport of LNG in certain types of rail tank cars.
The PHMSA also regulates pipeline safety and has adopted more stringent safety standards following several accidents. Under agreements with certain state agencies, the PHMSA allows the state agencies to administer federal safety standards for interstate pipelines. States are permitted to adopt stricter standards for state-regulated pipelines and several have done so.
Under current PHMSA regulations, the maximum administrative civil penalties for violation of the pipeline safety laws and regulations is US$2 million. State agencies have imposed even greater penalties. In April 2015, the California Public Utilities Commission approved the largest penalty it has ever assessed by ordering PG&E shareholders to pay US$1.6 billion for the unsafe operation of its gas transmission system, including the pipeline rupture in San Bruno, California, in 2010 that resulted in eight fatalities and extensive property damage. In July 2014, the US Attorney for the Northern District of California filed a separate criminal indictment against PG&E alleging obstruction of the National Transportation Safety Board's investigation of the San Bruno incident and knowing and wilful violations of the Pipeline Safety Act (PSA). In August 2016, the jury in the federal district court case found PG&E guilty of five felony counts of violating the PSA and one felony count of obstructing a federal investigation. In sentencing proceedings in January 2017, the federal district court ordered the company to pay a maximum fine under the PSA of US$3 million, placed the company on probation for five years, ordered the company to complete 10,000 hours of community service (including 2,000 hours by high-level personnel) and ordered the establishment of a court-appointed monitor. Congress passed legislation in 2016 amending the PSA and reauthorising the PHMSA's pipeline safety programme until 2019. However, the legislation did not revise the standard for criminal liability under the PSA for pipeline safety violations, despite some senior DOT officials advocating a lower liability standard – from 'knowingly and wilfully' to 'recklessly'. Funding authorisation for the pipeline safety programme lapsed in October 2019, despite several bills introduced to continue it. The programme continues to operate under the Further Consolidated Appropriations Act of 2020 that includes pipeline safety appropriations for fiscal year 2020.
New final rule for underground natural gas storage facilities
Accidents have also precipitated new regulations for natural gas storage facilities. A high-profile leak of methane gas from the Southern California Natural Gas Company's Aliso Canyon–Porter Ranch underground storage field in October 2015 led to calls for increased regulation of underground natural gas storage facilities. In June 2016, Congress enacted the Protecting our Infrastructure of Pipelines and Enhancing Safety (PIPES) Act of 2016. Among other things, the Act required the PHMSA to issue, within two years, minimum safety standards for underground natural gas storage facilities. In addition, the PIPES Act allowed states to adopt more stringent safety standards for intrastate facilities, if the standards are compatible with the minimum standards prescribed in the Act. In December 2016, the PHMSA published an interim final rule that revised existing federal pipeline safety regulations relating to downhole facilities, including wells, well bore tubing and casing at underground natural gas storage facilities. The interim final rule also incorporated certain recommended practices of the American Petroleum Institute into the PHMSA's federal safety standards, including practices applicable to the design and operation of solution-mined salt caverns used for underground storage, and practices applicable to the functional integrity of natural gas storage in depleted hydrocarbon reservoirs and aquifer reservoirs. In February 2020, the PHMSA published a final rule, incorporating many of the comments and concerns received, including modifying compliance timelines, clarifying the states' regulatory role and reducing reporting requirements. The final rule formalises requirements for operators to implement integrity management programmes and to conduct risk assessments for underground natural gas storage facilities. The final rule also requires that operators of underground natural gas storage facilities file annual reports, obtain operator identification numbers, and file incident and safety-related reports. The final rule applies to intrastate storage facilities and requires states to update their safety regulations to include the specified recommended practices. The final rule became effective in March 2020.
The State of Texas and the Texas Railroad Commission had petitioned the US Court of Appeals for the Fifth Circuit for review of the interim final rule. In 2017, the Fifth Circuit Court of Appeals had granted an abeyance in anticipation of the final rule. Now that the final rule has been issued, the case will probably resume.
Three new PHMSA final rules
The PHMSA has been active in the rule-making process. In October 2019, it issued three final rules that were each several years in the making: (1) Safety of Gas Transmission Pipelines: Maximum Allowable Operating Pressure Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments Rule (the Gas Pipelines Safety Rule); (2) Safety of Hazardous Liquid Pipelines Rule; and (3) Enhanced Emergency Order Procedures Rule.
Work preceding promulgation of the Gas Pipelines Safety Rule began in April 2016, when the PHMSA published proposed revisions to its safety regulations for onshore natural gas transmission and gathering pipelines, to address incidents like the San Bruno rupture. The 2016 proposal received a significant number of comments and was re-evaluated before publication of the final rule. The final rule broadens the scope and strength of the PHMSA's natural gas pipeline safety regulations by adding new assessment and repair criteria for gas transmission pipelines, and by extending those protocols to pipelines located in newly designated moderate consequence areas (i.e., areas where an incident would pose a risk to human life through an impact circle containing five or more buildings intended for human occupancy, a highway and other occupied areas). In addition, the rule:
- codifies requirements for pipeline operators periodically to assess certain gas transmission pipelines outside high concentration areas to monitor, detect and remediate pipeline defects and anomalies;
- requires reporting of exceedances of the maximum allowable operating pressure (MAOP) of gas transmission pipelines;
- requires certain devices on in-line inspection, launcher or receiver facilities that can safely relieve pressure in the barrel;
- requires the use of a device that can indicate whether the pressure has been relieved in the barrel; and
- requires operators of certain onshore steel gas transmission pipeline segments to reconfirm the MAOP of those segments.
The Gas Pipeline Safety Rule comes into effect in July 2020.
The Safety of Hazardous Liquid Pipelines Rule extends reporting requirements to certain hazardous liquid gravity and rural gathering lines not previously regulated by the PHMSA. It requires inspections of pipelines in areas affected by extreme weather or natural disasters, extends the use of leak detection systems to all regulated hazardous liquid pipelines and requires integrity assessments at least once every 10 years for onshore hazardous liquid pipeline segments located outside high concentration areas. This rule also comes into effect in July 2020.
The Enhanced Emergency Order Procedures Rule affects the PHMSA's role during an emergency. Here, the PHMSA may issue an emergency order without advance notice or opportunity for a hearing. Additionally, the PHMSA may impose emergency restrictions, prohibitions or other safety measures on owners and operators of gas or hazardous liquid pipeline facilities, but only to the extent necessary to abate the imminent hazard. This rule stems from a 2016 interim final rule and has been updated to respond to comments received, including, for example, clarifying that an emergency order is not to be used as a substitute for notice and comment rule-making, and must be issued only to the extent necessary to abate the imminent hazard. This rule became effective in December 2019.
Conclusions and outlook
Energy regulation in the United States remains complex and multilayered, and will continue to evolve for the foreseeable future. Competing economic and political interests (including effects on ratepayers and taxpayers, and state policy initiatives aimed at increased deployment of clean energy resources and decreased GHG emissions) cause conflict surrounding jurisdictional issues, energy security, transmission system planning, pipeline development, cost allocation, renewable development and integration, and many other issues. The variety of energy industry participants and regulators, and the geographical differences across the United States, can provide an opportunity for the development of innovative policies but this heterogeneity may also lead to disjointed or overlapping regulatory obligations and may ultimately undermine the development of a uniform national energy policy.
1 Tyler Brown, Eugene R Elrod, Michael J Gergen, Natasha Gianvecchio and J Patrick Nevins are partners at Latham & Watkins LLP. The authors gratefully acknowledge the contributions of their associate colleagues – James B Blackburn IV, Richard H Griffin, Chris Randall and Samuel P Scott.
2 854 F.3d 9 (DC Cir 2017).
3 827 F.3d 122 (DC Cir 2016).
4 Revised Policy Statement on Treatment of Income Taxes, 162 FERC ¶ 61,227 (2018); SFPP, L.P., Opinion No. 511-C, 162 FERC ¶ 61,228 (2018).
5 164 FERC ¶61,030 (2018).
6 Opinion No. 511-D, 166 FERC ¶ 61,142 (2019).
7 See SFPP, L.P. et al. v. FERC, D.C. Cir. Nos. 18-1252, et al. and 19-1067, et al.