I OVERVIEW

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.

II REGULATION

i The regulators

Multiple federal and state agencies, departments and other governmental entities regulate US energy development, and the ownership, control and operation of electric energy, natural gas and oil production, gathering, transmission/transportation and distribution of energy resources, including with respect to the rates, terms and conditions of wholesale and 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, including the Federal Power Act (FPA), as amended, the Natural Gas Act (NGA), as amended, the Natural Gas Policy Act of 1978, as amended, the Interstate Commerce Act, as amended, the Energy Policy Act of 2005, and the Public Utility Holding Company Act of 2005.

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.

The Department of Energy (DOE) is an executive department created in 1977 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'. The DOE is led by the Secretary of Energy, a member of the President's cabinet. FERC is within the DOE, and the 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, the 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, Pipeline and Hazardous Materials Safety Administration (PHMSA), Environmental Protection Agency, 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 of energy facilities (except LNG facilities), 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.

ii Regulated 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 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 charges and typically 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 upward 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 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 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 prohibited FERC from regulating the rates, terms, and conditions of service for LNG terminals, but only until January 2015, at which time FERC's authority over LNG terminals became the same as its authority over interstate natural gas pipelines; however, FERC has not yet exercised that authority and instead has continued to allow LNG import and export terminals to charge market-based rates and to operate without complying with FERC's 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.

Pipelines located in US waters on the 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 and Bureau of Safety and Environmental Enforcement. Offshore pipelines located within three miles of the United States are also often subject to state regulation.

State PUCs generally regulate the distribution and delivery of electricity and natural gas to retail customers, including rates, terms and conditions for retail sales and distribution of electric energy and natural gas, and the safe and reliable delivery of electricity and natural gas to retail customers in the state. State PUCs may also regulate rates and operating conditions for intrastate natural gas pipelines and storage services and for intrastate deliveries of liquid fossil fuels by pipeline. Siting approvals for the development and construction of new energy facilities are often required at the state or local government level.

iii Gathering, terminalling, processing, and treatment of natural gas and oil

In states where natural gas and oil exploration and development is active, state agencies often possess regulatory authority over gathering (typically the collection and transportation of resources 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.

iv Ownership, market access restrictions and transfers of control

The Committee on Foreign Investment in the United States oversees foreign investment in existing companies and assets in the United States, 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. In reviewing the 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 is 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 services, including rates.

FERC also regulates the direct and indirect transfer of 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 effect on competition, the effect on rates and the effect on 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 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 provide net benefits to the public.

III TRANSMISSION/TRANSPORTATION AND DISTRIBUTION SERVICES

i Vertical 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.

Prior to the mid-1980s, the natural gas industry was fairly rigidly structured into three parts:

      • a producers that sold natural gas to pipeline companies;
      • b 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
      • c distributors that sold natural gas to retail customers.

Certain large industrial and electrical generating companies bought natural gas directly from producers or pipelines. In an effort to open natural gas markets to widespread competition, FERC initially voided contractual requirements that distributors purchase minimum quantities of natural gas from pipelines. These orders were followed by new open access rules requiring interstate pipelines to offer ‘unbundled' transportation services (i.e., transportation services not tied to purchases of natural gas from the transporting pipeline or its affiliates) at tariff rates on non-discriminatory terms and conditions set by FERC for all pipelines, and requiring compliance with new standards of conduct that prohibit pipeline transportation personnel from communicating non-public, competitively sensitive information to marketing personnel. FERC also required interstate natural gas pipelines to establish internet-based information systems to facilitate reporting and use of available pipeline capacity, as well as 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. In 1989, Congress first deregulated sales of natural gas by producers and FERC then adopted rules that effectively deregulated the price of all other wholesale sales of natural gas. 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. The reforms led to highly competitive natural gas sales markets in the United States, where only pipeline transportation and distribution services and certain storage services are subject to rate regulation.

The electric sector in the United States was also dominated by 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 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 sales 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.

ii Rates

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 that appear to it to be over-earning. Pipelines and storage companies are also permitted to offer discounts from the maximum, cost-based rate discounts, as well as to negotiate rates with customers. Any rate discounts offered by an interstate natural gas company must be offered on a non-discriminatory basis to all similarly situated customers, and 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 if either they offer the customer the option to take service under a FERC-approved cost-of-service rate, known as a ‘recourse rate', or they demonstrate to FERC that competition is sufficient to prevent the exercise of market power. Storage companies are often permitted to charge competitive market-based rates.

For interstate deliveries, FERC jurisdictional pipelines that transport fossil fuel liquids may charge cost-of service rates, historical rates (where applicable) or market rates if adequate competition is proven to exist. FERC-regulated oil pipeline rates may change 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 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 pipelines if offered to all shippers and prospective shippers in an open season. FERC permits oil pipelines to offer priority service for part of the new capacity if open-season shippers pay a premium rate and all shippers have an opportunity to subscribe to capacity in an open season. FERC also permits pipelines to offer unreserved capacity at discounted rates through an open-season offering, and has also approved proposals to allow committed shippers who pay such discounted rates to receive priority service during periods of prorationing by paying a premium rate.

iii Security and technology restrictions

Prior to 2005, the United States relied on voluntary compliance by participants in the bulk power industry with reliability requirements for operating and planning the bulk power system coordinated through the North American Electric Reliability Corporation (NERC) and various related regional entities. In 2005, Congress responded to a widespread August 2003 blackout throughout the 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 facility 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. The natural gas and oil industries are voluntarily implementing measures to maintain security and are cooperating with federal agencies to develop and implement safeguards.

IV ENERGY MARKETS

i Development of wholesale electric energy markets

Throughout certain regions in the United States, ISOs and RTOs operate transmission facilities and administer organised wholesale electric energy 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 left considerable discretion to market participants to determine an ISO's or RTO's governance structure, geographical scope and type of market services.

The following ISOs and RTOs are currently operating: 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, as ERCOT is deemed to be electrically isolated from the rest of the 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. 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. 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 an energy imbalance market system 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 are active participants in this system.

ii Wholesale 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, which is subject to the exclusive jurisdiction of the Public Utility Commission of Texas. The independent market monitor within each RTO and ISO provides independent oversight over certain market issues, including with respect to market concentration issues.

iii Contracts for sale of electric energy at wholesale

The US electricity markets have a long history with bilateral power purchase and sale contracting at wholesale. Even 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 financial settlements. 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.

iv Natural gas and oil markets

Unlike in the electricity sector, there are no formal FERC-approved organised wholesale markets for oil and natural gas. 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 more efficiently use transportation services, FERC allows exceptions to its shipper-must-have-title rule under qualifying asset management arrangements. No similar rules, requirements or exceptions apply to pipelines that transport fossil fuel liquids.

v Retail 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 early 2017, 14 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.

V RENEWABLE ENERGY AND CONSERVATION

i Development of renewable energy

The United States does not have comprehensive policies 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 also 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 MWh of generation output, and 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 new Trump administration took initial steps in early 2017 to reverse or revoke the Clean Power Plan, though 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:

  • a 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;
  • b 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
  • c 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 EPAct) of 1992, and was most recently 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 EPAct 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 for whose construction commenced by the end of 2011, although projects not yet placed in service are 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 $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 operates various loan guarantee programmes for clean energy projects established under Title XVII of the EPAct of 2005 and ARRA, Sections 1703 and 1705. ARRA provided the DOE with guarantee authority under Section 1705 for commercial projects employing renewable energy systems, electric power transmission systems, or leading-edge biofuels, and appropriations to cover federal credit subsidy costs (i.e., loan loss reserves) of up to $2.5 billion for projects that commenced construction by 30 September 2011. Accordingly, the DOE issued approximately $16 billion in full or partial guarantees for 31 renewable energy projects (predominantly solar projects) between September 2010 and September 2011. The DOE has not closed on a loan or loan guarantee for a renewable energy project since September 2011, although the federal government reported that as of January 2013, the DOE had $2.3 billion in remaining loan guarantee authority for energy-efficiency and renewable energy projects, and was then considering using $2 billion of the remaining loan guarantee authority for loan guarantees requested by eight active applications. In December 2013, as part of the Obama administration's Climate Action Plan, the DOE issued a solicitation making available up to $8 billion in loan guarantees under Section 1703 to support innovative advanced fossil energy projects that avoid, reduce or sequester GHGs. In February 2014, the DOE issued two loan guarantees under Section 1703 for approximately $6.2 billion to two entities involved in the development and construction of a nuclear power plant in Georgia. In July 2014, the DOE issued a solicitation making available up to $4 billion in loan guarantees under Section 1703 (made up of $2.5 billion in guarantee authority and approximately $170 million in remaining appropriations to cover credit subsidy costs) to support innovative renewable energy and efficient energy projects. In August 2015, the DOE issued supplements to this solicitation and another outstanding solicitation regarding advanced fossil energy projects to clarify both that the DOE will accept and consider applications for ‘distributed energy projects' and that state-affiliated financial entities, including state green banks, may submit applications for eligible projects and participate in distributed energy projects as lenders or co-lenders, equity providers, or offtakers (i.e., entities purchasing the energy output of the 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 have higher target levels; e.g., 50 per cent by 2030 in California and New York, 100 per cent by 2045 in Hawaii) 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 that is expected to reduce the economic attractiveness of distributed solar electric 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, at least in part, for the foreseeable future (and as discussed in Section VI, infra, California not only strengthened its renewable portfolio standard during 2011, it also implemented its own GHG cap and trade programme beginning in 2012, which is intended, in part, to support greater deployment of renewable generation resources). Moreover, a number of states and local governments are actively considering establishing, and since 2011 three states and one local government, most notably the state of New York, have established, public-private partnership clean-energy financing entities, commonly referred to as ‘green banks', to support deployment of renewable energy and energy-efficiency projects.

ii Energy efficiency and conservation

The United States has a limited set of comprehensive policies regarding promotion of energy efficiency for electric appliances and energy efficiency standards for federal buildings and properties. In addition, the federal government has various targeted grants and financing support programmes as well as tax incentives for energy efficiency investments. Moreover, as discussed above, the Environmental Protection Agency's Clean Power Plan proposes in part avoided fossil fuel-fired generation output from end-use energy efficiency measures as a means to comply with proposed limits on CO2 emissions from existing generating facilities.

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.

VI THE YEAR IN REVIEW

i Electricity

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.

As noted above, 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 the most reliable, efficient and cost-efficient solutions. The major reforms of Order No. 1000 include:

  • a 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;
  • b 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;
  • c 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
  • d 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.

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 energy 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 energy markets; however, the RTOs were still given flexibility as to how to implement these market incentives. RTOs began proposing revisions to their market rules to FERC during 2011 to comply with Order No. 745 and FERC acted on a number of these compliance filings during 2011 and 2012. Order No. 745 was challenged before the DC Circuit on a number of grounds, including that the substance of Order No. 745 exceeds FERC's jurisdiction under the FPA, as it seeks to regulate retail sales of electricity by requiring RTOs to pay retail customers for not consuming electricity at retail. In a decision issued in May 2014, the DC Circuit vacated Order No. 745, holding, among other things, that FERC did not have jurisdiction to issue 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 wholesale markets. The Supreme Court held that RTOs' 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"' (emphasis in original).

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 the ISO-New England and PJM sought to improve generator reliability during these periods by significantly revising their forward capacity markets. ISO-New England's new capacity market rules, referred to as ‘performance incentive' or ‘pay for performance' were adopted in 2014, and PJM's proposal, referred to as ‘capacity performance', was 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 commences in June 2018. All capacity resources that clear the PJM market will be 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 generating facilities.

In October 2015, the Supreme Court agreed to hear a federal pre-emption case involving the effort by some states to subsidise the construction of new electric generating facilities through long-term power purchase arrangements mandated by the states. In those cases, the states' load-serving entities were participants in PJM's capacity market, and the subsidised generating facilities would receive the out-of-market compensation conditioned on their clearing the PJM capacity market. This issue came to the Supreme Court as a result of litigation in 2013 and 2014 before lower federal courts that held that procurement programmes in Maryland and New Jersey for the construction of new generation capacity violated the Supremacy Clause of the US Constitution because they impermissibly intruded on FERC's exclusive jurisdiction under the FPA over wholesale sales (i.e., sales for resale, including PJM's capacity market). The case involving the Maryland procurement programme was decided by the US Court of Appeals for the Fourth Circuit (the Fourth Circuit), while the case involving the New Jersey procurement programme was decided by the US Court of Appeals for the Third Circuit (the Third Circuit). In April 2016, the Supreme Court issued a decision affirming the Fourth Circuit's decision holding that ‘Maryland's program sets an interstate wholesale rate, contravening the FPA's division of authority between state and federal regulators'. The Supreme Court further provided that ‘States may not seek to achieve ends, however legitimate, through regulatory means that intrude on FERC's authority over interstate wholesale rates, as Maryland has done here.' At the same time, the Supreme Court provided that its holding was ‘limited' and need not and did not ‘address the permissibility of various other measures States might employ to encourage development of new or clean generation, including tax incentives, land grants, direct subsidies, construction of state-owned generation facilities, or re-regulation of the energy sector'. Shortly after issuing its decision affirming the Fourth Circuit striking down Maryland's programme, the Supreme Court declined to review the Third Circuit decision striking down New Jersey's programme.

At the state level, during 2016 a few states 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 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 compensation for distributed energy resources, and energy efficiency programmes, development of community distributed generation and retail choice aggregation, 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 $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. 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 have pointed to the ‘RIIO' or ‘revenue equals incentives plus innovation plus outputs' framework used by regulators in Britain as a possible model.

Relating to the Clean Energy Standard, regulators in New York 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. Regulators in New York concluded 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 and regulators in other states in the United States are considering similar types of compensation mechanisms, though, as of early 2017, the compensation mechanisms in New York and Illinois are being challenged both 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. FERC is considering mechanisms to include carbon pricing (or other mechanisms to implement state policy goals) in an RTO bid-based market.

On 1 June 2017, President Trump announced that he planned to have the United States withdraw from the Paris Agreement.

ii Natural 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. 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 northeastern 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 recent years, FERC continued to approve new rights for committed shippers on new and expanded pipelines that transport oil and other liquid fossil fuels who participate in an open season process. FERC allowed these shippers to receive priority to subscribe to future available capacity or future expansion projects following the open season. FERC also approved tiered rates for shippers based on the size of their acreage dedications. Other FERC orders, however, reinforced the limits of FERC's flexibility, such as orders denying priority service to shippers who enter into contracts after (but not during) an open season, and refusing to pre-approve uncommitted shipper rates for new and expanded 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 could have broad rate implications for the interstate pipeline industry. In United Airlines v. FERC, 827 F3d 122 (DC Cir 2016), the DC Circuit sided with pipeline shippers who challenged FERC's income tax allowance policy. FERC's income tax allowance policy, which has been in place since 2005, allows partnerships 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 made clear 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 in December 2016 seeking input from industry participants on how to address any double-recovery resulting from its current income tax allowance policy and policies regarding the derivation of return on equity. FERC has received two rounds of comments in response to the Notice of Inquiry. Depending on how FERC rules on the issue on remand, its decision could have a significant impact on the rates charged by interstate oil and natural gas pipelines that are organised as partnerships or other pass-through entities.

Since 2013, FERC has 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. One of these projects completed its first phase of construction and commenced commercial operation in early 2016, making it the first facility to export LNG to overseas markets from the lower 48 United States. In total, six LNG export projects are under construction (including expansions of existing facilities or construction of new facilities). Three approved projects have yet to begin construction. In 2017, the Maritime Administration approved the first proposed floating liquefaction LNG export project pursuant to the Deepwater Port Act.

Several of the FERC orders approving these LNG projects were appealed to the DC Circuit. 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 asserted by some environmental non-governmental organisations. 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. Environmental groups also asserted that approval of LNG exports would contribute to increased GHG emissions. 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 effects of the LNG exports, in part because the 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. FERC was not obligated to consider the cumulative effects of other LNG terminals nationwide that either had been recently approved or whose applications for approval were still pending.

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.

The DOE has authorised nine large-scale LNG projects 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. Numerous other companies that have proposed to develop LNG export projects have applied to FERC and the DOE for similar authority and their applications are pending. Challenges to many of the DOE's orders authorising exports of LNG to non-FTA countries are pending before the DC Circuit and should be decided in 2017.

In August 2014, the 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. The 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, the 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 after such a change in control has occurred. For changes in control related to existing authorisations or pending applications for authorisations to export to non-FTA countries, the DOE will consider properly submitted protests of such changes in control but the DOE will take no action unless it determines that the change in control renders the underlying authorisation at issue inconsistent with the public interest.

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, the 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 the 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; however, 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. However, President Obama 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 Keystone XL 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 for the Keystone XL pipeline, making a determination that issuance of the Presidential Permit ‘would serve the national interest'. Despite the State Department's issuance of the Presidential Permit, many regulatory and legal steps remain for the Keystone XL pipeline. The Presidential Permit grants 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. The remaining miles of Keystone XL pipeline in the US have to be approved by various other regulatory bodies, including state regulatory bodies in Montana, South Dakota and Nebraska, before construction can commence. At the time of publication, Montana and South Dakota have issued approvals for construction of their respective segments of the pipeline, but consideration of the Keystone XL pipeline by the Nebraska Public Service Commission is still under way, with fierce opposition from Nebraska farmers and landowners. Litigation is likely in connection with each of these regulatory decisions, and may potentially further delay the construction of the Keystone XL pipeline.

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 US ‘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. As of the date of publication, the Secretary of Commerce has not submitted such plan. In March 2017, the White House clarified that the Presidential Memorandum will not apply to the Keystone XL pipeline, because the Keystone XL pipeline does not constitute a ‘new' pipeline under the Presidential Memorandum.

In response to a series of highly publicised accidents involving trains carrying crude oil from the Bakken, 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 has 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 $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 Pacific Gas & Electric Company (PG&E) shareholders to pay $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 $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. In January 2017, the Gas Pipeline Advisory Committee convened the first of at least two meetings 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. The final rule is expected later in 2017.

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 April 2017, PHMSA announced the user fee requirements that will apply to operators of underground storage facilities in order to fund federal and state safety and oversight activities.

VII CONCLUSIONS AND OUTLOOK

Energy regulation in the United States remains complex and multilayered and will continue to evolve for the foreseeable future. Competing economic and political interests (including effects on ratepayers and taxpayers, and state policy initiatives aimed at increased deployment of clean energy resources and decreased GHG emissions) cause conflict surrounding jurisdictional issues, energy security, transmission system planning, 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 Eugene R Elrod, Michael J Gergen, Natasha Gianvecchio, J Patrick Nevins and David L Schwartz are partners at Latham & Watkins LLP.