Energy regulation in the United States is complex, broad and enforced by a variety of federal and state governmental 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 be an overview of the nature and scope of energy regulation and markets.


iThe regulators

Multiple federal and state agencies, departments and other governmental 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 as the Federal Power Commission to license hydroelectric facilities and regulate wholesale sales of electric energy and natural gas and the transmission of electric energy or 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 Acts of 1992 and 2005, the Public Utility Holding Company Act of 2005 and the Department of Energy (DOE) Organization Act of 1977.

The Nuclear Regulatory Commission (NRC) is an independent federal regulatory agency established by Congress to formulate policies and regulations governing nuclear reactor and materials licensing and safety. The NRC’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.

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 within DOE, and, under the DOE Organization Act, DOE and FERC sometimes have overlapping and sometimes have 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). At the same time, under the NGA, 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 Commodities 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-based and locally-based 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.

iiRegulated activities

Many aspects of energy development, generation, production, transmission/transportation, and distribution in the United States 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 natural gas and oil pipeline transportation services. Entities making sales of FERC-jurisdictional products or services obtain rate approval from FERC. FERC rates for electric 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 with respect to 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 abandonment of existing) interstate natural gas pipeline and storage facilities and, as discussed previously, 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 to, among other things, 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 electric 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 electric 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 passage of 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 the 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 the DOE’s NIETC designation authority under the FPA remains unclear as a result of judicial decisions in the US Courts of Appeals.

PHMSA regulates the safety of most US pipelines and LNG terminals. Although PHMSA is responsible for enforcement of US laws setting minimum pipeline and LNG safety standards, 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. 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 (BOEM) 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.

iiiGathering, 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 may regulate a 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, PHMSA, BSEE and the Occupational Safety and Health Administration.

ivOwnership, 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, 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 electric transmission and generation facilities. In reviewing a proposed transfer of electric transmission or generation facilities, 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.

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 PHMSA regulations, including drug-testing, recordkeeping 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.


iVertical integration, unbundling and open access

Over 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:

  1. producers that sold natural gas to pipeline companies;
  2. 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
  3. 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 the transporting pipeline or its affiliates). A few years later Congress passed the Natural Gas Wellhead Decontrol Act of 1989, lifting price controls on sales of natural gas by producers. FERC then 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 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. Also 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 US, Canada, and Mexico).

FERC has continued to implement reforms to liberalise US natural gas markets by requiring compliance with new 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. During these same periods, 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.

Electric sector

The electric sector in the United States was also initially dominated by vertically integrated franchised monopolies. Prior to the early 1990s, vertically integrated electric 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 electric 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 electric 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 electric 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, such 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 most recently, 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 adopted significant reforms of FERC’s transmission planning and cost-allocation rules established previously in Order No. 890. Order No. 1000 sought to address significant recent 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:

  1. 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;
  2. 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;
  3. 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
  4. 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. FERC required public utility transmission providers to begin making filings with FERC during 2012 that proposed revisions to their transmission planning processes under their respective OATTs to comply with Order No. 1000. Throughout 2013, FERC issued orders regarding some of these compliance filings in which it accepted and rejected various proposed revisions, including rejecting a number of proposals to retain certain types of rights of first refusal for incumbent transmission providers to build and own transmission projects eligible for socialised cost recovery. 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 (DC Circuit). In August 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.

Over the past several years, the US electricity industry has evolved to become more dependent on natural gas caused by relative decreases in natural gas prices along with 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 electric industries interact. After several years of technical conferences and public comments on these issues, in April 2015, FERC issued Order No. 809, entitled ‘Coordination of the Scheduling Processes of Interstate Natural Gas Pipelines and Public Utilities’, adopting proposals submitted by an industry forum to modify the scheduling practices used by interstate natural gas pipelines to schedule natural gas transportation service and provide additional contracting flexibility to firm natural gas transportation customers through the use of multiparty transportation contracts and revised nomination timelines. FERC also directed each FERC-jurisdictional RTO and ISO to propose tariff revisions to coordinate its day-ahead energy market with the scheduling practices adopted in Order No. 809 or to show cause why its existing scheduling practices need not be changed.

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. 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 twentieth 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, however, 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. Today, while 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.

In 2005, Congress amended the FPA to direct FERC to develop rate incentives to encourage certain transmission development. In 2006, FERC issued regulations to provide on a case-by-case basis a variety of cost-of-service rate incentives for new transmission projects that improve reliability or reduce cost. These incentives include incentive rates of return on equity for new investment, 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.

Since 2000, FERC has also permitted certain merchant 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 upfront or assured ongoing 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 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 such investigations, typically targeting a few pipelines once each year or every other year. 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 voluntarily reduce its rates).

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’) in order 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.

For interstate deliveries, FERC-jurisdictional pipelines that transport fossil fuel liquids (oil pipelines) may charge cost-based rates; or they may charge market-based rates if adequate competition is proven to exist in the pipeline’s 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 a premium over ‘uncommitted’ (walk-up) rates, and all shippers had an opportunity to contract for the new capacity in an open season.

iiiSecurity 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 northeastern and midwestern United 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 governmental 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 PHMSA. PHMSA regulates pipeline facilities pursuant to its pipeline safety programme, which is implemented in cooperation with the states. Although 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 PHMSA to regulate intrastate pipelines. If a state’s law does not meet the federal minimum safety standards, 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 such 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.


iDevelopment 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 are currently operating 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 ERCOT 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 electric 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 of the existing ISOs and RTOs administer some form of bid-based markets for one or more energy products (i.e., where 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. Such forward capacity markets are structured differently in each RTO and ISO 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 eastern portion 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 June 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 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, as well as 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 RTO and ISO provides independent oversight over certain market issues, including with respect to market structure, conduct and performance issues. RTOs and ISOs 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 RTOs nor ISOs 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.

iiWholesale energy market rules and regulation

Each RTO and ISO develops its own market rules through the market participants’ stakeholder approval process. Market rules for all RTOs and ISOs 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.

iiiContracts 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 where market participants are located within an applicable RTO or ISO (i.e., bidding or offering into the organised wholesale markets and scheduling flows through the RTO or ISO), 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 electric quarterly reports.

ivNatural 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, like the Intercontinental Exchange or bilateral contracts. As with purchase and sale agreements for electricity, such 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 individualised 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 ICA, FERC historically has refrained from involvement in crude oil marketers’ use of interstate oil pipelines – except to insure 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. That ruling is currently the subject of further review by FERC in response to requests for rehearing and clarification. Also, 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.

vRetail energy market regulation

Retail energy markets are regulated at the state and local levels. Across much of the United States, retail consumers of electricity and natural gas 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. Beginning in the mid-1990s there was 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 northeastern United States, 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 as well as 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 United States, which had a severe negative impact on the financial conditions of the restructured utilities in California and ultimately compelled the state of California to become a significant buyer of last resort in the wholesale electricity markets and ended retail competition for most retail consumers in California. After the California electricity 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 one of these states, New York, 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 if retail suppliers should be completely prohibited from serving their current product offerings to mass-market customers. As of early 2019, this proceeding is still pending. Since the early 2000s, a number of states have allowed for the creation of community choice aggregation (CCA) arrangements, whereby a local entity, often an entity 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 already 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.


iDevelopment 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. The Environmental Protection Agency (EPA) issued regulations regarding CO2 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 CO2 per megawatt-hour (MWh) of generation output. The Clean Power Plan proposes in part increased generation output from renewable energy resources, as well as 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. Final steps to unwind the Clean Power Plan are expected to require regulatory actions that in and of themselves will take a year or more and are expected to be subject to legal challenges that may not be resolved before the next presidential election in 2020.

The federal government provides or has provided various tax incentives for renewable energy, including:

  1. a production tax credit (PTC) (per energy generated) for wind, geothermal, biomass and some other renewable energy resources (not including solar and fuel cells) for a period of 10 years from the date the renewable energy facility is placed in service;
  2. 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
  3. 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 Energy Policy Act (the EP Act) of 1992, and was extended to include projects that commence construction prior to 1 January 2020, with a phase down in the credit amount for projects commencing construction after 31 December 2016. 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. 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 in 2009 through 2013 (2009 through 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 expenditures by the federal government. The federal government estimates that as of July 2012 it provided approximately US$13 billion in cash grants for over 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 ARRA, Sections 1703 and 1705. As of early 2019, the LPO has approved more than US$30 billion of loans and loan guarantees for more than 30 projects, and has over US$40 billion available for loans and loan guarantees. As of January 2017, the LPO has 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.

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 have target levels as high as 100 per cent by 2045 and others have recently increased their targets as discussed below in Section VI) and what types of energy resources qualify (e.g., fuel cells, waste energy, combined heat and power (CHP), 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 electric systems) to supply excess generation to their retail electricity supplier in exchange for credits against their retail electricity bills over 12-month and sometimes longer periods. 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 in the United States 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, that 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. 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 as well as installation cost rebates or performance-based payments for solar and certain other renewable resources (e.g., wind, fuel cells and CHP).

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 past years, and has been proposed in various pieces of legislation. However, given current fiscal concerns and related political disagreements over the nature and role of federal financial support for clean energy, the prospects for such legislation remain unclear. At the same time, state-based renewable portfolio standards, as well as net metering, tax incentive and rebate programmes for distributed renewable generation resources appear poised to remain in place or be expanded, 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.

iiEnergy 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 electric 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 to recover 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 recover of and on these investments through special charges included on the customer’s retail utility bill. A similar type 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’s Order No. 745 was adopted in 2011 to encourage demand responsiveness through market pricing mechanisms. In Order No. 745, FERC required that the RTO- and ISO- 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 RTOs and ISOs were still given flexibility as to how to implement these market incentives. RTOs and ISOs 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 Order No. 745 exceeds FERC’s jurisdiction under the FPA, as it seeks to regulate retail sales of electricity by requiring RTOs and ISOs 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 Order No. 745 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 RTOs’ and ISOs’ payments 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”’.



Numerous states this year 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 meanwhile continued to grapple with how best to accommodate advanced technologies such as battery storage and the ongoing evolution of the mix of resources that supply electric energy, capacity and ancillary services. Fossil-fuelled generators again comprised nearly all retirements in 2018 and are increasingly being replaced by renewable resources despite attempts by the executive branch of the federal government to prevent ‘baseload’ generators from retiring. NERC also demonstrated the seriousness with which it takes cybersecurity standards by issuing a record-setting penalty, and California’s largest investor-owned utility filed for 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. California passed SB 100 in 2018, which requires that 100 per cent of the electricity consumed in the state must come from carbon-free sources by 2045. In doing so, California became the first state to join Hawaii in legislating a 100 per cent clean energy target. Hawaii passed legislation in 2015 calling for 100 per cent of its electricity to come from renewable resources by 2045. Since then, New Mexico, the District of Columbia and Puerto Rico have also adopted 100 per cent clean energy targets. New York’s and Washington’s governors have also each committed to achieving 100 per cent carbon-free electricity, by 2040 and 2045, respectively. Other states are also considering more ambitious clean energy targets. In March, Wisconsin’s governor proposed in a budget to decarbonise the state’s electricity supply by 2050, and Minnesota’s governor released his own budget calling for 100 per cent clean electricity in his state by 2050. Legislation is also currently pending in Illinois that would call for 100 per cent renewable energy by 2050. These advances are indicative of the recent trend to increase renewable portfolio standards (RPS) across the country. For example, between 2015 and 2017, Vermont increased its RPS to 75 per cent by 2032, Oregon increased its RPS to 50 per cent by 2040, and Maryland increased its RPS to 50 per cent by 2030.

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, Massachusetts passed an energy bill in August that would require a minimum percentage of electricity sales to end use customers come from clean peak resources as well as setting a 1 gigawatt (GW) target for energy storage by 2025. At least five states in total have so far adopted targets specifically for energy storage, including New York, which set a target to procure 3GW of energy storage capacity by 2030.

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 across the United States. Since 2018, several north-eastern states created or increased their commitment to offshore wind energy. For example, New Jersey Governor Phil Murphy announced in January a goal of developing 3.5GW of offshore wind generation by 2030, which was adopted by the state legislature in May. The New Jersey Board of Public Utilities subsequently voted to open a solicitation in September for 1.1GW of offshore wind generation capacity – the largest single-state offshore wind generation solicitation to date. New York also established goal of procuring 2.4GW of offshore wind generation capacity by 2030, and issued a solicitation for 800MW in November. In January of 2019, New York Governor Cuomo announced further plans to increase the state’s procurement target to 9GW by 2035. Massachusetts selected winning bidders for a solicitation for 800MW of offshore wind capacity in 2018 as well, and 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 $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. Connecticut agreed to purchase 200MW of offshore wind in June of 2018 and announced plans to purchase an additional 100MW in December. California, Delaware, Hawaii, Maine, Maryland, New Hampshire, North Carolina, and Virginia 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 Eire near Cleveland, Ohio.

The continued rise of energy storage

The deployment of energy storage resources in the United States nearly doubled in 2018, with approximately 311MW/777MWh of energy storage capacity installed. The amount of energy storage in the United States is expected to double again in 2019, and by 2024, deployments are expected to exceed 4.4GW. 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 & 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 February 2018 and thereby directed RTOs and ISOs to remove barriers to the participation of electric storage resources in the organised wholesale electricity markets by requiring the RTOs and ISOs to establish market rules that facilitate such participation and take into account the physical and operational characteristics of electric storage resources. While requests for rehearing of Order No. 841 remain pending, all six RTOs and ISOs other than ERCOT filed implementation plans with FERC in December 2018. The implementation plans garnered significant testimony from stakeholders, and in April 2019, FERC issued deficiency letters asking each of the six grid operators to provide additional detail with respect to various aspects of their proposals. The RTOs and ISOs have 30 days to respond to FERC’s letters, and FERC directed the RTOs and ISOs to implement changes by 3 December 2019.

Fossil-fuelled generator retirements

The amount of power-generating capacity retired in the United States increased significantly from 2017 to 2018, with 11.6GW retired in 2017 and 18.7GW retired in 2018. Coal-fired generators made up nearly 70 per cent of the capacity retired in 2018, with gas-fired resources accounted for another 25 per cent of 2018 retirements. The 12.9GW of coal-fired capacity retired in 2018 marks the highest level of retirements of coal-fired generators since a record of 14.8GW was set in 2015. While fossil-fuelled generation still accounted for 63.5 per cent of electricity produced by utility-scale generation facilities in the United States in 2018, these retirements follow a continuing trend. Nearly all of the utility-scale power plants in the United States that were retired from 2008 through 2017 were fossil fuel-fired. In 2007, coal-fired generation capacity in the United States totalled 313GW across 1,470 generators. In the 10 years following, 529 of those coal-fired generators, with a total capacity of 55GW, have retired. Most of the planned retirements through 2020 are also coal-fired power plants and natural gas steam turbines. Looking ahead, projections show that some 7.4GW of little used gas-fired generating capacity is expected to retire by 2026 and an additional 21.4GW of coal-fired generating capacity will retire by 2024. The majority of generation capacity additions in 2018 – approximately 62 per cent – were comprised of more efficient natural-gas fired generators, while wind, solar, hydro and battery storage capacity constituted all remaining additions. No new coal-fired generation capacity was added in 2018.

In August 2017, in response to a request from the Secretary of Energy, the staff of DOE issued a study in August 2017 regarding the wholesale electricity markets and grid reliability in which they found that the wholesale markets, especially the organised markets administered by RTOs and ISOs, 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 RTOs and ISOs to establish tariff mechanisms providing for the purchase of energy from generation resources and the recovery of costs and a return on equity for such resources located in an RTO/ISO 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 RTOs and ISOs, 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. In March 2018, one company submitted an application with the Secretary of Energy to declare that an emergency exists in PJM within the meaning of FPA Section 202(c) with respect to a threat to energy security and reliability. The application seeks to direct that certain nuclear and coal-fired generation facilities in PJM (including the company’s nuclear and coal-fired generation facilities, which the company asserts are at risk of retirement) enter into contracts and all necessary arrangements with PJM, on a plant-by-plant basis, to generate, deliver, interchange and transmit electric energy, capacity and ancillary services to maintain fuel diversity and grid dependability and resiliency within the PJM region. This effort is highly controversial and is being opposed by PJM and many other market participants (including the owners of some of the nuclear and coal-fired generation facilities that are the subject of the application).

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’ (CASPR), 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 of PJM’s proposals as inadequate with respect to addressing the competitive impacts 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 where 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 have been submitted in these proceedings and as of early May 2019, FERC had yet to issue an order directing PJM how to restructure its capacity market despite its pledge to make every effort to issue an order establishing a replacement structure by 4 January 2019. PJM’s next capacity auction, which is typically run in May, has been pushed back to August, although questions remain as to whether the auction will be run at that time and if so, pursuant to what rules.

Record default in PJM financial markets

The largest default in the history of PJM’s financial markets occurred in 2018 with the default of GreenHat Energy LLC (GreenHat). Over the course of approximately three years, GreenHat obtained a portfolio of financial transmission rights (FTRs) valued at over US$150 million while providing only limited amounts of collateral given PJM’s rules that were in place at the time. An FTR functions as a hedge on transmission congestion and is used to help energy buyers, generators, and distributors protect against local price swings.

On 21 June 2018, PJM declared that GreenHat was in default after missing a weekly payment of US$1.2 million. As a result of the default, and in accordance with its operating agreement, PJM began liquidating the FTR positions on which GreenHat had defaulted in July. However, PJM quickly halted this liquidation process as it began to observe market illiquidity and large risk premiums for GreenHat’s positions, which could have resulted in significant losses for PJM’s members. PJM then began a stakeholder review process under which new procedures for liquidating GreenHat’s portfolio were developed. PJM also agreed to create a new chief risk officer position, institute training programs for risk management and conduct a general review of its FTR market.

In October 2018, PJM proposed rule changes to FERC to address future defaults and also requested that they be applied retroactively. While FERC accepted these rules going forward, FERC denied PJM’s request to apply the rules retroactively and noted that its Office of Enforcement is conducting an investigation of GreenHat’s actions. The denial of the waiver request, however would require PJM to rerun the July 2018 FTR auction. Further, PJM would be required to recalculate the default allocation assessments made to date for GreenHat’s FTRs that went to settlement during the period of September 2018 through January 2019 if those FTRs are liquidated when the auction is rerun. PJM estimates that this process could result in a revised total default reference of at least US$430 million and result in US$250 million to US$300 million in increased total default allocation assessments to PJM members. Multiple parties sought rehearing of FERC’s order denying PJM’s waiver request, and those requests for rehearing remain pending.


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. 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 published a US$2.7 million fine on 31 May 2018, for one utility that reportedly left usernames, passwords and grid information unsecured.

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 a review of 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.

Ongoing 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, that calls for ‘animating markets’ at the distribution level so that retail customers and third parties (e.g., energy service companies, retail suppliers, demand-management companies) can monetise the economic values that distributed resources can provide to the overall electric system in New York. This initiative also tasks the electric 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 electric 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 are considering a wide range of issues relating to the REV initiative, including changes in their ratemaking practices for the electric distribution utilities, establishment of a new benefit–cost framework for electric distribution utility expenditures on investments in distributed system platforms, procurement of and 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 for encouraging the deployment of large-scale renewable energy generation, 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, and the development of a ‘Clean Energy Standard’ to succeed New York’s RPS (which expired at the end of 2015) that requires that 50 per cent of the electricity consumed in New York to come from clean energy sources by 2030. Relatedly and as discussed above, New York’s governor has since committed to achieving 100 per cent carbon-free electricity in the state by 2040. Regulators have indicated that changes in their ratemaking practices for electric 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 ratemaking changes for electric distribution utilities, including providing them with the ability to earn revenues from:

  1. the achievement of alternatives that reduce their capital spending and provide definitive consumer benefits;
  2. market-facing platform activities; and
  3. transitional outcome-based performance measures.

Zero emission credit programmes upheld

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 Illinois 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 Elec. Power Supply Ass’n 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 recently issued orders denying petitions for review of the Second and Seventh Circuits’ decisions.

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 (RECs)) 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. Green tariff programs vary in their implementation. Some programmes 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 PPA’ where the utility passes a physical power purchase agreement that it has signed with a renewable energy project along to the consumer. Green tariffs are now being used in particular by a number of larger IT firms, including Apple, which purchases from NV Energy’s GreenEnergy Rider programme, and Google, which utilises Duke Energy’s green tariff.

2018 was a record year for corporate clean energy contracts with approximately 75 deals accounting for 6.53GW, up from 2.78GW in 2017. Many of these participating companies were new entrants, with some 34 companies signing their first clean energy power purchase agreements in 2018. 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.

PG&E bankruptcy

California faced historically destructive wildfires in 2017 and 2018, with more than 8,000 wildfires burning approximately 1.8 million acres in 2018 alone. Among the most destructive of these wildfires was the Camp Fire, which destroyed nearly 14,000 residences and killed more than 80 people. Facing liability from these fires under the state’s inverse condemnation laws, which leave utilities subject to liabilities from wildfires if their equipment is involved, regardless of negligence, California’s largest investor-owned utility, PG&E, announced it would file 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, as well as an additional US$1 billion pre-tax charge related to 2017 wildfires. According to the company, its total potential wildfire liabilities could exceed US$30 billion. 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 related 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 over 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 has sought a preliminary injunction against FERC to prevent it from exercising its asserted concurrent jurisdiction. The injunction proceeding is ongoing and, regardless of the outcome, is expected to be appealed to the Ninth Circuit Court of Appeals following its issuance. 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 also considered splitting up the PG&E’s natural gas and electric divisions into separate companies. The bankruptcy proceeding remains pending and is expected to continue for two years or possibly longer.

iiNatural gas and fossil fuel 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 proposed and constructed, with the approval of FERC, large amounts of new infrastructure to serve the new production and transport the gas to markets. In 2016, for instance, FERC certificated approximately 17.6 billion cubic feet per day of new pipeline capacity. Pipeline certificate proceedings have increasingly been heavily contested, with significant opposition to many projects from certain environmentalist organisations and landowners. These organisations have challenged projects at FERC and, in many cases, appealed FERC’s rulings to the courts.

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-eastern United States. 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 individual 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 together before approving any one of them. The DC Circuit remanded the case, which involved one of the already built and operating segments, to FERC, 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 supplemental 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 of 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 re-approved the project after providing a supplemental 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 – with two of the five FERC Commissioners dissenting. 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.

Also in 2017, a number of state regulators responsible for issuing water quality determinations under the 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 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 another case involving Constitution Pipeline, the Second Circuit declined to decide a challenge to New York’s failure to issue a water quality determination, instead requiring that the pipeline first seek a waiver from FERC. FERC subsequently denied the pipeline’s waiver request because the state 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.

With respect to oil pipelines, 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 have 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, however, have defined the limits of FERC’s 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 July 2016, the DC Circuit issued a decision that ultimately had broad implications for the interstate pipeline industry. In United Airlines v. FERC, 827 F.3d 122 (DC Cir 2016), the DC Circuit sided with pipeline shippers that challenged FERC’s income tax allowance policy. FERC’s income tax allowance policy, in place since 2005, 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 concluded that FERC had acted arbitrarily and capriciously when it permitted the pipeline in question to include an income tax allowance in its rates, because FERC had failed to demonstrate that its income tax allowance policy together with its use of a discounted cash flow methodology to determine return on equity would not permit the pipeline’s limited partnership owners to double-recover their income taxes through the pipeline’s rates. The DC Circuit vacated FERC’s orders authorising the pipeline’s rates, and remanded the case to FERC for further proceedings. In its decision, the DC Circuit held that FERC is free to continue to provide partnerships and other pass-through entities with an income tax allowance if it either provides a sufficient explanation that its current policy does not result in double-recovery of taxes for such entities, or takes another approach to assure there is no double-recovery.

In response to the United Airlines decision, FERC issued a Notice of Inquiry (NOI) in December 2016 and received two rounds of comments in response to the NOI. In March 2018, FERC ruled on the issue on remand, announcing in its ruling and in a revised policy statement that FERC will no longer permit MLPs to recover an income tax allowance in cost-based rates because such recovery allows an impermissible double recovery of income taxes. Going forward, FERC announced that other pass-through entities may be allowed to recover the income tax allowance in cost-based rates, but only if they address the double recovery concern expressed in United Airlines and the revised policy statement. The same day, FERC issued orders initiating a rulemaking and another NOI to evaluate whether the recent lowering of the US corporate tax rate from 35 to 21 per cent should be reflected in individual oil and gas pipelines’ cost-based rates, or trigger other changes to rates in response to recent changes in US tax laws.

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 encourage 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 do 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 of 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 may 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.

Under FERC’s approach in the final rule, oil pipeline rates will be reduced through FERC’s next round of five-year indexing adjustments in 2020, to be effective 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.

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. Three of these projects (Cheniere’s Sabine Pass and Corpus Christie terminals and Dominion Cove Point) have completed construction and are exporting cargos from the lower 48 United States. Exports from three additional projects (Elba Island, Cameron LNG, and Freeport LNG) are expected to commence operations in 2019. In early 2019, FERC authorised its first new LNG export project in over two years, the Venture Global Calcasieu Pass Project, and then authorised two additional projects (Port Arthur and Driftwood) just a few months later.

Several FERC orders approving LNG projects were appealed to the DC Circuit by the Sierra Club and similar non-governmental 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 impacts. 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 US, 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 geographic area.

In early 2016, FERC denied the applications to construct the Jordan Cove LNG export terminal in southwest 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. In the absence of more tangible evidence, FERC determined that the project was not in the public interest because the proven benefits of the project did not outweigh the detriment to approximately 630 landowners, including 54 intervenors, whose property would be disturbed by the pipeline. FERC also determined that the LNG export terminal is not feasible without the pipeline. The project’s proponents sought rehearing (essentially reconsideration) of FERC’s order, which FERC denied, and later filed a new application with supplemental support demonstrating market support for the pipeline.

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) that found that such 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. For changes in control related to existing authorisations or pending applications for authorisations to export to non-FTA countries, DOE will consider properly submitted protests of such changes in control but DOE 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 United States trade sanctions), including countries without free trade agreements to which the United States is a party, that require national treatment for trade in natural gas (non-FTA countries). DOE issued such 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 US will experience net economic benefits from LNG exports. Relying in part on this study, DOE authorised LNG exports to non-FTA nations for the three LNG export project authorised by FERC in 2019, promptly following issuance of the FERC authorisations. Numerous other companies proposing to develop LNG export projects have applied to FERC and the DOE for similar authority and their applications are pending.

Environmental groups 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 impacts 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 are required for the construction and operation of facilities that cross the international borders of the United States, including facilities for the transmission or transportation of electricity, natural gas, crude oil and petroleum products between the United States and Canada or Mexico. The authority to issue Presidential permits has been delegated by the President to the Secretary of Energy for electricity, FERC for natural gas and 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 2015. 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.

At the Department of State, however, the Presidential permit process for the Keystone XL pipeline has not followed a similar pattern. The Keystone XL 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 (the Bakken) in the United States, to refineries in the US Midwest. Much of this oil is transported by rail today. An application for a Presidential permit for the Keystone XL pipeline was filed with the Department of State in May 2012. The application was strongly opposed by environmental groups, and the Secretary of State in the Obama administration did not issue a decision on the then-pending application. In February 2015, Congress passed a bill approving the Keystone XL project and deeming all statutory environmental requirements to have been satisfied. President Obama then vetoed the bill, and a vote to override that veto in the US Senate failed in March 2015.

In November 2015, the Secretary of State in the Obama administration denied the application for the Presidential permit for the pipeline, finding that the pipeline would only marginally benefit the US economy and energy security, but would ‘significantly undermine [the United States’] ability to continue leading the world in combating climate change’. In March 2017, the State Department in the new Trump administration reversed course and granted the application for the Presidential permit, making a determination that issuance of the Presidential permit ‘would serve the national interest’. The Presidential permit granted permission to ‘construct, connect, operate and maintain’ the pipeline facilities at the international border between the US and Canada, and therefore applies to only 1.2 miles of pipeline. This permit was soon challenged in the US District Court in Montana. In November 2018, the court ordered to halt construction of the project, stating that the Department of State had failed to give a ‘hard look’ at the potential effects of greenhouse gas emissions, failed to consider impacts on cultural resources, and must supplement its prior work with new and relevant information regarding the risk of oil spills. In March 2019, the Trump administration released a Presidential permit in response to this order, again authorising the construction of the pipeline. Because the new permit was issued directly from the Office of the President and not delegated through the State Department, the government argued in an April 2019 motion to dismiss that the new permit, unlike the prior permit is not subject to the review under the Administrative Procedure Act. As of the time of writing, the District Court has not ruled on this motion.

In the meantime, certain legislative initiatives have attempted to disentangle the Keystone XL pipeline from the District Court decision. In June 2018, Senator John Hoeven (R, North Dakota) introduced a bill that would move cross-border pipeline approvals from the State Department to FERC. This is similar to a July 2017 bill that passed the US House of Representatives. Both bills have since stalled in the Senate.

Aside from Keystone XL’s cross-border pipeline segment, the remaining miles of the pipeline in the United States have been approved by other regulatory bodies, including state regulators in Montana, South Dakota and Nebraska. However, Nebraska’s approval requires an alternate route that adds 63 miles to the pipeline. In Canada, preliminary construction work has already begun.

In January 2017, President Trump signed a presidential memorandum directing the Secretary of Commerce, in consultation with all relevant executive departments and agencies, to develop a plan under which all ‘new pipelines, as well as retrofitted, repaired or expanded pipelines, inside the borders of the US’, use materials and equipment produced in the United States ‘to the maximum extent possible and to the extent permitted by law’. The presidential memorandum directed the Secretary of Commerce to submit such a plan within 180 days of the date of the memorandum. After issuing a request for comment in March of 2017, the Department of Commerce engaged in no further action on the issue, missing the 180-day deadline.

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 among other matters established operating standards for crude oil conditioning equipment and prohibited operators from blending lighter hydrocarbons into crude oil before shipment. 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 the transportation of crude oil by rail. PHMSA and the 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 the type of tank car, 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 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 railroads 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.

PHMSA also regulates the safety of pipelines and, following several pipeline accidents, has adopted more stringent safety standards for pipelines. Under agreements with certain state agencies, 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 in recent years. Effective as of 25 October 2013, PHMSA adopted new rules increasing the maximum administrative civil penalties for violation of the pipeline safety laws and regulations after 3 January 2012 to US$2 million for a related series of violations. 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). The PG&E case was tried in federal district court during the summer of 2016. 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 PHMSA’s pipeline safety programme through 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’.

Meanwhile, PHMSA continues to review and revise its existing pipeline safety standards. Among its most significant recent regulatory proposals are two companion rules addressing pipeline safety and integrity, one applicable to hazardous liquid pipelines (which include crude oil and natural gas liquids pipelines) and another applicable to natural gas pipelines. The October 2015 proposal governing hazardous liquid pipelines would have extended existing integrity management requirements to previously-exempt pipelines and would have imposed additional obligations on hazardous liquid pipeline operators that are already subject to existing integrity management requirements., The proposal also would have required operators to evaluate annually the protective measures they have implemented on pipeline segments that operate in ‘High Consequence Areas’ where pipeline failures have the highest potential for human or environmental damage, would have established shorter repair timelines for critical pipeline repairs, and would have tightened the standards for pressure tests. PHMSA issued a final rule in January 2017, just prior to inauguration of the newly elected US president. The final rule modified certain aspects of the proposed rule to address concerns expressed by the regulated industries during the comment period, but retained key aspects of the rule regarding expanded inspection, leak detection, and reporting requirements. The rule was withdrawn in late January 2017.

In April 2016, PHMSA published proposed revisions to its pipeline safety regulations applicable to onshore natural gas transmission and gathering pipelines. The proposed rule would significantly broaden the scope and strength of PHMSA’s safety regulations by adding new assessment and repair criteria for natural gas transmission pipelines and by extending such protocols to pipelines located in newly designated ‘Moderate Consequence Areas’ where an incident would pose a risk to human life. In addition, the proposed rule would, among other things, modify assessment and repair criteria for pipelines inside and outside High Consequence Areas, provide additional direction to pipeline operators on how to evaluate internal inspection results, expand mandatory data collection and integration requirements for integrity management, and require a systematic approach for verifying a pipeline’s maximum allowable operating pressure (MAOP) and reporting of MAOP exceedances. The April 2016 proposal would also revise the definition of gathering lines, and repeal an exemption for natural gas gathering line reporting requirements. The proposed changes regarding gathering lines in particular have received opposition from industry. In January 2017, the Gas Pipeline Advisory Committee convened a meeting to discuss the proposed revisions, which would extensively modify Part 191 and Part 192 of the federal pipeline safety regulations applicable to gas transmission and gathering pipelines. Additional meetings were held in 2017 and are expected to be held through June 2018 to discuss, among many other technical requirements, the application of the new regulations to gathering lines. The resulting rule or rules are likely to issue in mid-to-late 2018.

Responding to the high-profile leak of methane gas from the Southern California Natural Gas Company’s Aliso Canyon/Porter Ranch underground storage field in October 2015 and calls from the Obama administration to act, PHMSA issued an Advisory Bulletin in February 2016 addressing the operation of underground storage facilities used for the storage of natural gas. In the Advisory Bulletin, PHMSA recommended that all operators of underground natural gas storage facilities have processes, procedures, mitigation measures, periodic assessments and reassessments, and emergency plans in place to maintain the safety and integrity of all wells and associated storage facilities, whether those facilities are operating, idled, or plugged. PHMSA specifically instructed operators to review their operations to identify the potential for leaks and failures caused by corrosion, chemical damage, mechanical damage or other material deficiencies in piping, tubing, casing valves, and associated facilities.

On 22 June 2016, the US Congress enacted the Protecting our Infrastructure of Pipelines and Enhancing Safety (PIPES) Act of 2016. Among other things, the act required 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 such standards are compatible with the minimum standards prescribed in the Act. On October 14, a federal interagency task force convened to study the issue and released a final report and fact sheet on underground natural gas storage regulation. The task force was co-chaired by the DOE and PHMSA, and included members from numerous federal, state, and local government agencies. The report included 44 recommendations regarding well integrity, public health and environmental effects, and energy reliability. On 19 December 2016, as required by the Act, PHMSA published an interim final rule that revised existing federal pipeline safety regulations related to downhole facilities, including wells, wellbore tubing, and casing at underground natural gas storage facilities. The interim final rule also incorporated certain recommended practices of the American Petroleum Institute into 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. The interim 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 interim final rule also applies to intrastate storage facilities, and requires states to update their safety regulations to include the specified recommended practices. The interim final rule became effective on 18 January 2017, and owners and operators are expected to implement the new requirements by 18 January 2018.

The state of Texas and two natural gas and pipeline industry trade associations have filed separate petitions for review of PHMSA’s interim final rule, which are pending at the US Court of Appeals for the Fifth Circuit and the DC Circuit. Texas contends that the interim final rule impermissibly overrides the state’s authority to regulate intrastate underground natural gas facilities, while the trade associations challenge the timeframes for implementation and certain technical aspects of the interim final rule. In 2017, the petitions and enforcement of the interim final rule was stayed while PHMSA solicited additional comments.


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, cost allocation, renewable development and integration and many other issues. The variety of energy industry participants and regulators, as well as the geographical differences across the United States, can provide an opportunity for the development of innovative policies, but such 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, J Patrick Nevins and David E Pettit are attorneys at Latham & Watkins LLP.