The majority of modern environmental legislation in the UK is derived from EU law, either from directives that have been implemented by UK domestic legislation or from regulations that apply directly in EU member states such as the UK. With the advent of the UK’s withdrawal from the EU following the referendum held last June, the question has arisen as to the effect of “Brexit” on UK environmental law. There is little clarity on this question now, as the UK government has yet to unveil its strategy on how and when it will implement Brexit. It remains unclear whether the UK government will seek to adopt an already-established model of being outside of but closely linked to the EU – for example, that of non-EU states that are part of the European Economic Area (EEA) such as Iceland, Liechtenstein and Norway, or that of European Free Trade Association (EFTA) states that are not EU or EEA members but gain market access to the EU primarily through bilateral agreements, such as Switzerland – or a wholly bespoke arrangement. In practice, any approach that is bilateral – and a complete severance of ties seems unlikely – will also require the consent of, and therefore be shaped by, EU member states. Perhaps because of this and also to some extent because of geographic proximity and common trans-boundary concerns, it seems likely that EU environmental law will remain relevant to the development of UK environmental law and policy. As a starting point, the referendum itself has no legal effect on the laws of the UK or EU. The UK will remain a member of the EU until there is either an agreement to exit or expiration of a two-year period after a formal notice of exit is issued by the UK government. This notice, when served, triggers a negotiation period of up to two years during which time the current EU laws continue to apply in the UK. The UK government has not yet issued this notice. During the transitional period that ensues, the UK government will need to conduct a complex review of what existing environmental legislation derived from the EU should continue to apply, including where the legislation is directly set out in EU text, taking the necessary steps to adopt domestic legislation for its implementation. Such a review will naturally be guided by the broader thinking on the UK-EU relationship after Brexit is implemented. If the UK opts to remain in the EEA as a non-EU state, “Norwegian” style, it will be required to formally continue to adopt most EU environmental legislation, including in areas such as environmental permitting, air and water quality, greenhouse gas emissions, waste, electrical and electronic equipment and chemicals registration. Under a bilateral agreement model or bespoke arrangement, more freedom would be afforded to the UK to set its own course regarding operational environmental controls within its own borders. For example, Switzerland is not required to comply with EU environmental legislation by virtue of its EFTA membership only. In practice, Switzerland has put in place bilateral agreements with the EU to gain access to the EU single market, which in turn have resulted in the country harmonizing much of its environmental legislation with that of the EU. As with any country outside European institutions altogether, the UK would still be required to meet EU environmental and safety standards regarding products being placed onto the EU market. For example, the sweeping EU law governing the registration and safety analysis of chemicals, known by its acronym REACH, requires chemical manufacturers in the rest of the world wishing to sell their products into the EU to appoint an “EU Only” Representative that ensures REACH compliance. In addition, certain environmental laws govern inherently trans-border or regional concerns, such as those dealing with global greenhouse gas emissions reduction and control (Kyoto Protocol) or marine pollution (the OSPAR Convention). There is no indication that the UK government would push back strongly on its existing commitments under these laws. Over the last 25 years, the UK has been at the forefront of certain environmental protection legislation, and some prominent UK domestic legislation does not derive from the EU. Two notable examples are the UK’s contaminated land regime, which established in the UK a “polluter pays” principle for cleanup of soil and groundwater contamination before similar legislation was introduced at EU level, and the Climate Change Act of 2008, which established very ambitious targets to reduce greenhouse gas emissions domestically by 80% from 1990 levels by 2050. It is not likely that Brexit would trigger major changes in these areas.
At their respective national conventions in late July, the Democratic and Republican Parties established the policy platforms on which their respective federal, state and local candidates will base their election campaigns. Those platforms present very different prescriptions for the US energy sector. The energy plank of the 2016 Democratic Party platform, “Combat Climate Change, Build a Clean Energy Economy, and Secure Environmental Justice,” focuses on addressing climate change, pledging to “reduce methane emissions from all oil and gas production and transportation by at least 40 to 45% below 2005 levels by 2025,” reducing oil and natural gas consumption and increasing renewable energy use. In contrast, the energy plank of the 2016 Republican platform, “A New Era in Energy,” focuses on state as opposed to federal regulation of the energy sector and increased domestic energy production, including oil, natural gas and nuclear, as well as on federal lands. The Democratic and Republican Party platforms also present fundamentally opposing positions on a number of energy sector issues. With respect to hydraulic fracturing – “fracking” – the Democrats “are committed to closing the Halliburton loophole that stripped the Environmental Protection Agency (EPA) of its ability to regulate hydraulic fracturing,” and “believe hydraulic fracturing should not take place where states and local communities oppose it,” while the Republicans “support upholding” the decision of a federal judge who “has struck down the [Bureau of Land Management’s] rule on hydraulic fracturing,” and “respect the states’ proven ability to regulate the use of hydraulic fracturing, methane emissions, and horizontal drilling.” The Republicans “intend to finish the Keystone Pipeline,” while the Democrats “support President Obama’s decision to reject the Keystone XL pipeline.” The Democrats believe “the tax code must reflect our commitment to a clean energy future by eliminating special tax breaks and subsidies for fossil fuel companies as well as defending and extending tax incentives for energy efficiency and clean energy.” On the other hand, the Republicans “support the development of all forms of energy that are marketable in a free economy without subsidies, including coal, oil, natural gas, nuclear power, and hydropower,” and “encourage the costeffective development of renewable energy sources – wind, solar, biomass, biofuel, geothermal, and tidal energy – by private capital.” The Republicans “oppose any carbon tax” and “urge the private sector to focus its resources on the development of carbon capture and sequestration technology still in its early stages here and overseas,” while the Democrats believe that “carbon dioxide, methane and other greenhouse gases should be priced to reflect their negative externalities, and to accelerate the transition to a clean energy economy and help meet our climate goals.” The Democrats “are committed to defending, implementing and extending smart pollution and efficiency standards, including the Clean Power Plan, fuel economy standards for automobiles and heavy-duty vehicles, building codes and appliance standards, while the Republicans “will do away with [the Obama Administration’s Clean Power Plan] altogether.” The Republicans “support the enactment of policies to increase domestic energy production, including production on public lands, to counter market manipulation by OPEC and other nationally-owned oil companies,” while the Democrats “believe America must be running entirely on clean energy by mid-century” and “are committed to getting 50% of our electricity from clean energy sources within a decade, with half a billion solar panels installed within four years and enough renewable energy to power every home in the country.” While the Democrats commit to “transform American transportation by reducing oil consumption through cleaner fuels, vehicle electrification increasing the fuel efficiency of cars, boilers, ships, and trucks,” and “make new investments in public transportation and build bicycle and pedestrian infrastructure across our urban and suburban areas,” the Republican platform does not address this issue. While the Republicans posit that “American energy producers should be free to export their product to foreign markets,” and “remain committed to aggressively expanding trade opportunities and opening new markets for American energy through multilateral and bilateral agreements, whether current, pending, or negotiated in the future,” the Democratic Party platform does not address US energy exports. One issue on which the two parties might be said to agree is promoting new electricity transmission lines. The Democrats pledge to “streamline federal permitting to accelerate the construction of new transmission lines to get low-cost renewable energy to market,” while the Republicans “applaud” congressional Republicans for passing bills that “will modernize pipelines and the electric grid” and promising to “build on these policies.”
The publication of the draft strategy for the UK Oil and Gas Authority (OGA) to give effect to the maximization of economic recovery (known as “MER UK”) was a welcome development, but further guidance and detail was needed on implementing the strategy. The next step in this process took place on May 12, 2016 with the granting of Royal Assent to the Energy Act 2016 (the “Act”). The Act furthers the recommendations of the Wood Review and establishes the OGA as the independent regulator for the UK oil and gas sector by transitioning it from an Executive Agency of the Department of Energy and Climate Change (DECC) to a company incorporated under the Companies Act 2006. Substantial changes for the UK oil and gas landscape1 are set out in the body of the Act addressing the core functions of the OGA, the resolution of disputes in the sector, information-gathering powers of the OGA, sanctions and charges, and access to infrastructure and decommissioning. This article summarizes the impact of the Act on each of those topics. The OGA, Its Functions and Powers From its establishment as an Executive Agency of the DECC, the OGA was given “sufficient operational independence to be effective from day one” 2 and the responsibility for a range of functions of the Licensing Exploration and Development unit,3 including exercising certain statutory functions on behalf of the Secretary of State. Prior to Royal Assent being given to the Act, this was broadly managed pursuant to a Framework Document4 clarifying the OGA’s operation and governance, and the exercise of rights, influence and control by the Secretary of State while the OGA remained an Executive Agency.5 These arrangements were designed to be consistent with the intended OGA operation and governance arrangements, post-transition. The Act advanced the transition, giving effect to the next stage by renaming the Oil and Gas Authority Limited as the Oil and Gas Authority,6 clarifying its relationship with the Crown7 and formally transferring to it certain functions of the Secretary of State for Energy and Climate Change.8 The Secretary of State was given the power9 to transfer property, rights and liabilities from the remit of a Minister of the Crown to the OGA. Staff were also transferred10 to the new corporate entity and arrangements made in relation to staff pensions.11 While initially very little might change in OGA operations, the transition sets the platform from which long-term decisions for the industry can now be taken. A supplementary Framework Document reflecting the new arrangements is expected in Q3 2016 to clarify the nature of the relationship between the DECC and the OGA further, but it is expected that the day-today functions in matters such as licensing, licensing strategy and policy, exploration activities, decommissioning, field and area strategies, managing infrastructure, consents, metering, supply chain issues and commercial relationships and managing the industry portal will continue to be managed independently by the OGA.12 However, certain responsibilities have been supplemented or developed further by the Act, as described in the remainder of this article. Dealing With Disputes It is widely accepted that the UKCS is a challenging jurisdiction in which to operate, being a mature basin with aging infrastructure and increasingly diverse operators. The Act also provides the OGA with the powers necessary to resolve certain disputes due to high operating costs, limited access to funding and a change in approach to regulation to achieve MER UK. The OGA has said that it “will use the new regulatory powers … such as those relating to dispute resolution and sanctions, prudently to improve UKCS operating performance in line with MER UK.”13 So what are these new powers and to what disputes are they applied? The Act gives the OGA power to consider and make recommendations to resolve “qualifying disputes”14 that involve issues relevant to the fulfillment of the MER UK or that relate to activities carried out under an offshore license, and are not the subject of a section 82 application.15 An OGA application for recommendation must be made by a “relevant party” (a party to the dispute who has a relevant purpose and is either a holder of a petroleum license, an operator under petroleum license, an owner of upstream petroleum infrastructure or planning and carrying out the commissioning of upstream petroleum infrastructure16) “in such manner as the OGA may require,” and the Act permits the OGA to make different provisions for different cases.17 Information Gathering by the OGA The OGA’s role as a primary regulatory body is reinforced by its power to request from industry participants, by notice in writing, a wide range of petroleum-related information and samples, provided they are acquired in relation to fulfilling the principal objective of MER UK or in the course of licensed activities.18 While such provisions arguably give the OGA access to a broad range of information, an affected party has limited appeal rights in front of a Tribunal. A certain degree of comfort is offered by the strict safeguards for any obtained information where the OGA is only allowed to disclose such information to other branches of government and regulators, and only to the extent such disclosure is relevant to their functions. Sanctions and Charges The Act establishes a comprehensive sanctions regime to allow the OGA to target and sanction different categories of noncompliance. The OGA’s power to levy these sanctions is triggered by industry participants’ breach of a “petroleum-related requirement” which captures: (i) a duty to act in accordance with the MER UK; (ii) compliance with the terms or conditions of an offshore license; or (iii) any requirement imposed by the Act which is itself sanctionable, for instance a failure to comply with an OGA information request.19 Prior to levying a sanction, the OGA must inform the relevant person of the alleged breach by giving a warning notice. The actual sanctions are imposed through four gradated types of notices, through enforcement, financial penalty, revocation of a petroleum license and operator removal. The Act provides for the publication of guidance relating to the circumstances in which the OGA will consider a financial penalty,20 but no equivalent requirement is included for license revocation and operator removal notices. Any sanctions notice can be appealed within 28 days of issue. Access to Infrastructure Third parties seeking to access upstream infrastructure, but unable to agree on satisfactory terms of access with the owner, can make an application to the OGA to require access to be granted and to determine the terms on which it is to be granted a “section 82 application.”21 The Act amends the Energy Act 2011 to allow for an application to access to be assigned to another party.22 It also introduces an element of continuity where the ownership of infrastructure that is the subject of an application has been transferred, by allowing all things done by the person to whom the application was made to be treated as done by its new owner.23 Any information provided by the third-party applicant to the OGA may be disclosed to the assignee of the application or to the new owner of the related infrastructure asset, provided that anything which might affect the commercial interests of the person providing the information has been removed. Decommissioning and Abandonment With several fields in the UK North Sea coming closer to their end of life, there is naturally a great deal of focus on how the MER UK will interact with operators’ decommissioning plans, whether or not submitted in connection with a section 29 notice.24 The Act creates a new section 28A to the Petroleum Act 1998 which expressly prevents abandonment or decommissioning of an offshore installation or submarine pipeline unless an appropriate program has been approved by the Secretary of State. It is an offense to start decommissioning without this approval.25 The Act places an emphasis on keeping costs low in any decommissioning program, with a statutory obligation to frame any plan in such a way as to allow decommissioning to be carried out at the lowest practicable cost and be reasonably practical in the circumstances, without prejudice to existing obligations under primary and secondary legislation, such as in relation to environment or health and safety. There is also a new duty on owners of offshore installations to act in accordance with the MER UK strategy when planning and carrying out the activities of an owner, or decommissioning an installation or infrastructure.26 The Act clarifies that this includes consideration of preservation or re-use and other uses than that for which the infrastructure was originally created. However, the Act remains light on specifics as to how such actions should be carried out beyond this general obligation. Conclusions The approach of the reforms that might be described as “guidance before intervention” is commended. The Act has continued to entrench this welcomed approach. In this and many other respects, the OGA will act as a guiding hand to the industry, providing direction that is in the best interests of MER UK – a sensible development, particularly in light of the recent political uncertainty created by Brexit. However, it is questionable whether the brevity of the strategy remains the right approach, and until the OGA has had time to build up a body of decisions and precedent, there will be uncertainty as to what is required to demonstrate that license holder plans are cost-efficient, or are indeed maximizing economic recovery. This will only be answered, as the OGA demonstrates, through action, that it is achieving its aims and meeting the industry’s needs.
On August 1, 2016, the White House Council on Environmental Quality published its final guidance to federal agencies requiring the consideration of greenhouse gas (GHG) emissions and effects on climate change when evaluating potential environmental impacts of federal agency action pursuant to the National Environmental Policy Act (NEPA). NEPA requires US federal agencies to prepare an environmental impact statement setting out the environmental impacts of and alternatives considered to federal agency actions that are deemed to have a significant environmental impact. As federal agency decisions related to permitting significant projects such as energy production or infrastructure development will often implicate NEPA, the Council’s final GHG guidance is relevant to sponsors of these projects and their financial institutions. The Council had issued two previous versions of the GHG guidance, the first in 2010 and a revised version in 2014. Changes to the final guidance were subject to public review and comment. Although the guidance is not legally binding, it is very likely that federal agencies will incorporate it into their reviews as they have done in the past with respect to other guidance issued by the Council. Moreover, both industry and environmental groups are likely to invoke the final guidance in disputes over a project as evidence to support their position that an agency has or has not complied with NEPA. The over-arching message of the final guidance has not changed: federal agencies should consider GHG emissions and potential climate change impacts as part of their analysis of project alternatives under NEPA. This analysis should include a quantitative analysis of GHG emissions whenever the tools and data are “reasonably available.” Agencies should use projected GHG emissions, including carbon sequestration implications, as a “proxy” for assessing potential climate change effects. The guidance also recommends that where agencies do not quantify a proposed agency action’s projected GHG emissions, they should include a qualitative analysis and explain the basis for determining that quantification is not reasonably available. The guidance does, however, continue to give agencies a lot of discretion to determine the extent of climate change impacts and their significance. The Council has eliminated the threshold in the 2014 revised guidance that federal actions resulting in emissions of 25,000 metric tons of CO2-equivalent or more should warrant a quantitative (rather than merely a qualitative) alternatives analysis of GHG emissions. The final guidance no longer establishes any specific threshold in this regard. Although the guidance emphasizes a “rule of reason” and that it is not advocating disproportionate attention to a quantitative review where climate change impacts are clearly minor, the elimination of this threshold may expand the scope of projects in which a quantitative analysis is conducted. In addition, the guidance clarifies its previous position that agencies should analyze both the direct and indirect GHG emissions that are reasonably foreseeable from a project. For example, the guidance suggests that a proper climate change impact analysis of coal extraction/production would also analyze the impacts from coal combustion as a reasonably foreseeable indirect impact. The final guidance will not apply to federal actions for which an NEPA review has been concluded or actions for which a final environmental impact statement or environmental assessment has already been issued.
On August 1, 2016, maximum civil penalties imposed by the US Environmental Protection Agency (EPA) and the Occupational Safety and Health Administration (OSHA) increased significantly pursuant to interim final rules these agencies published to implement a little-observed statute called the Federal Civil Penalties Inflation Adjustments Act Improvements Act of 2015. The new law, which became effective on November 2, 2015, requires federal agencies to make an initial “catch-up” adjustment through interim rulemaking, capped at a 150% increase over values in effect as of November 2, 2015. Thereafter, agencies must annually provide a review of statutory civil penalties accounting for inflation by January 15 on each year, beginning in 2017. The maximum increases announced by EPA and OSHA apply to civil penalties assessed after August 1, 2016 for violations that occurred after November 2, 2015. Under the EPA’s interim final rule, the maximum civil penalty EPA may recover varies depending on the regulations EPA is enforcing. Relevant key examples are as follows: Maximum penalties for violations under the Clean Air Act, 42 U.S.C. section 7413(b), for failure to comply with permits for major stationary sources increased from $37,500 to $93,750 per day per violation. Maximum penalties for violations of hazardous waste rules under the Resource Conservation and Recovery Act, 42 U.S.C. section 6928(g), increased from $37,500 to $70,117 per day per violation. Maximum penalties for violations of an effluent limit under the Clean Water Act, 33 U.S.C. section 1319(d), increased from $37,500 to $51,570 per day per violation. Maximum penalties for violations under the Emergency Planning and Community Right-to-Know Act, 42 U.S.C. section 11045(b)(1)(A), and the Comprehensive Environmental Response, Compensation and Liability Act, 42 U.S.C. section 9606(b)(1), for failure to comply with release reporting requirements increased from $37,500 to $53,907 per day per violation. In determining whether to seek a maximum penalty, EPA will continue to apply its civil penalty policies, which take into account a number of fact-specific considerations such as the seriousness of the violation, the violator’s good faith efforts to comply, any economic benefit gained by the violator as a result of its noncompliance and the violator’s ability to pay. On July 27, 2016, EPA made changes to several of its civil penalty policies in light of these increases, applying inflation adjustment multipliers under certain circumstances. In its interim final rule, OSHA increased maximum civil penalties by 78%, as OSHA had not made any inflationary increase since 1990. Relevant key increases are as follows: Maximum penalties for willful and repeated violations increased from $70,000 to $124,709 per violation. Maximum penalties for serious and other-than-serious violations increased from $7,000 to $12,471 per violation. Maximum penalties for failure-to-abate violations increased from $7,000 to $12,471 per day per violation. The Department of the Interior also increased civil penalties across a range of their bureau agencies, including the Office of Natural Resources Revenue, The Bureau of Land Management and the Office of Surface Mining Reclamation and Enforcement. The effective dates spanned from mid-July to early August 2016, with increases reflecting a range of 78% to 150%, depending on the agency. Some of the interim final rules provided comment periods.
On May 4, 2016, the Nuclear Installations (Liability for Damage) Order 2016 (the “2016 Order”) entered into force in the United Kingdom. The 2016 Order, which implements the 2004 Protocols27 to the Paris Convention28 and Brussels Supplementary Convention29 (together, the “Paris/Brussels Conventions”) into English law, revises the UK’s existing nuclear liability regime to ensure that, in the event of a nuclear incident, higher levels of compensation will be available to a wider group of victims and for broader categories of damage. This article explains the background to the 2016 Order, sets out its primary provisions and discusses its impact on the UK’s nuclear liability regime. It also considers additional and ongoing concerns with respect to the risk of exposure to nuclear liability from the perspective of nuclear licensees, their contractors and financial institutions doing business in the UK’s nuclear sector. Overview of the UK’s Nuclear Liability Regime Paris/Brussels Conventions The UK is a contracting party to the Paris/Brussels Conventions. The Paris/Brussels Conventions, which were developed under the auspices of the OECD, together establish an international regime governing liability in the event of a nuclear incident. The contracting parties to the Paris/Brussels Conventions are primarily OECD member states and include many Western European states.30 Non-OECD member states require the consent of the contracting parties to the Paris Convention in order to join the Paris/Brussels Convention regime. The Paris Convention sets forth the primary principles of civil liability for nuclear damage.31 Meanwhile, the Brussels Supplementary Convention makes available additional public funds if compensation payable under the Paris Convention is insufficient. These funds must be contributed jointly by all contracting parties according to a pre-determined formula. Together, the Paris/Brussels Conventions regime provides three tiers of funds: (i) operator funds; (ii) state (host country) funds; and (iii) joint funds from contracting parties to the regime. Joint Protocol The Joint Protocol Relating to the Application of the Vienna Convention and the Paris Convention (the “Joint Protocol”), 32 to which the UK is not a contracting party, links the Paris Convention with the Vienna Convention33 regime. The UK has said that it will consider becoming a contracting party to the Joint Protocol in the near future. In the meantime, however, the UK does not have treaty relations with any Vienna Convention countries. Therefore, claims brought in Vienna Convention countries are not covered by the UK’s nuclear liability regime. 2004 Protocols Background to the 2004 Protocols The UK is a signatory to the 2004 Protocols. However, these are not yet in force and, to enter into force, require ratification by two-thirds of the contracting parties to the Paris/Brussels Conventions. As envisaged by Council Decision 2004/294/EC of March 8, 2004,34 which authorizes EU member state signatories to ratify the 2004 Protocol to the Paris Convention, these EU member states will ratify the 2004 Protocols simultaneously. Ratification by these EU member states, which is expected to occur in early 2017, will be sufficient to bring the 2004 Protocols into force. The 2004 Protocols represent the modern iteration of international nuclear liability principles and generally follow the 1997 Vienna Convention (the modern iteration of the Vienna Convention) and the Convention on Supplementary Compensation (the “CSC”). 35 Their primary effect (which is explored further below) is to broaden the categories of damage and geographic scope of the Paris/Brussels Convention regime and increase the amount of compensation available to victims of a nuclear incident. Implementation of the 2004 Protocols into UK law In order to ratify the 2004 Protocols, the UK needed to promulgate implementing legislation. The Paris/Brussels Conventions are primarily implemented in the Nuclear Installations Act 1965 (the “NIA 1965”). The 2016 Order contains the amendments to the NIA 1965 to implement the 2004 Protocols.36 On February 22, 2016, the 2016 Order was laid before the UK’s House of Commons. An Explanatory Memorandum, prepared by DECC,37 was also published.38 Most of the provisions of the 2016 Order will come into force upon ratification of the 2004 Protocols. Effect of the 2004 Protocols The 2004 Protocols have been implemented in UK law in the following way: New categories of nuclear damage: Under the Paris Convention and the NIA 1965, an operator is liable for loss of life or personal injury and loss of or damage to property caused by a nuclear incident at its installation or involving nuclear material coming from its installation. The 2004 Protocols contain additional categories of nuclear damage, which are introduced into the NIA 1965 as follows: economic loss arising from personal injury or damage to property, although no changes are required under UK law since the NIA 1965 already permits recovery for economic loss; costs of measures of reinstatement39 of the impaired environment, unless such impairment is insignificant. To the definition in the 2004 Protocols, the 2016 Order adds the concept of “reasonable measures,” meaning that the costs and actual taking of such measures must be reasonable; loss of income deriving from a direct economic interest in any use or enjoyment of the environment, incurred as a result of significant impairment of that environment; and costs of preventive measures40 and further loss or damage caused by such measures. To the definition in the 2004 Protocols, the 2016 Order adds the concept of “reasonable measures” and adds a test to determine when such measures will be reasonable in circumstances of “grave and imminent threat.” Increased liability caps: The Paris/Brussels Conventions prescribe certain caps on an operator’s liability for each incident resulting in nuclear damage arising from that operator’s installation. An “operator” under the UK’s nuclear liability regime includes every UK nuclear site licensee. Under the 2016 Order: the liability of an operator of standard installations41 is raised from approximately £140 million (€170 million) to €1,200 million per incident; and an operator is made liable for both the first and second tier amounts below: Tier Liability cap Sources of funds under UK regime First €700 million Operator liable Second €500 million Operator liable, rising in annual increments of €100 million over five years Third €300 million Public funds, contributed by all contracting parties to the Brussels Convention The effect of the changes to the liability caps is effectively to shift greater liability for nuclear damage claims from the UK Government to operators. Notwithstanding this, although now permitted under the Paris/Brussels Convention regime, the UK Government’s current position is not to make an operator’s liability unlimited. Unlike certain other jurisdictions,42 the UK regime will therefore maintain a cap on the operator’s liability. Also, the third tier of funds is only available to Brussels Convention countries and would not be available to non-Brussels Convention countries. Extended claims limitation period: The limitation period for bringing a claim with respect to loss of life or personal injury will be extended from 10 years to 30 years. All other claims must continue to be brought within 10 years from the date of the incident. Expanded geographical scope: The Paris Convention and the NIA 1965 do not currently apply to any nuclear incidents occurring or damage suffered in a non-contracting state. Under the 2016 Order, the group of potential claimants is expanded to include those located in: states that have no nuclear installations on their territory at the time of the nuclear incident; and states that have in force, at the time of the nuclear incident, national nuclear liability legislation that: (i) affords equivalent reciprocal benefits; and (ii) is based on principles identical to those contained in the Paris Convention. This expanded geographical scope does not apply to the 2004 Protocol to amend the Brussels Convention, so claimants from countries captured by the expanded Paris Convention scope are not able to access the additional public funds available under the Brussels Convention. Inclusion of disposal sites: The UK’s nuclear liability regime is extended to cover installations for the disposal of nuclear substances, with the Secretary of State being empowered to prescribe different liability caps in proportion to the risk associated with different categories of installation. Generally, intermediate risk installations are prescribed a liability cap of €160 million (up from €140 million), with low-risk installations being prescribed a cap of €70 million (up from €10 million). Nuclear material shipping: The regime as it applies to shippers of nuclear material is also amended so that: liability can only pass from one shipper to another where the receiving shipper has a direct economic interest in the relevant nuclear material; and the shipping of nuclear material is deemed a low-risk activity, for which a liability cap of €80 million (up from €10 million) is generally prescribed. Geographic Coverage Issues Arising From 2004 Protocols Notwithstanding the expanded geographical coverage under the 2004 Protocols, certain foreign investors and contractors operating in the UK’s nuclear sector, their commercial banks and lending institutions should note the following: Joint Protocol and CSC As noted above, as the UK is not yet a contracting party to the Joint Protocol, there is no nuclear liability treaty relationship between the UK and Vienna Convention countries. Further, the UK is not, and is unlikely to become, a contracting party to the CSC, and therefore there is no nuclear liability treaty relationship between the UK and CSC countries (including the US and Japan). Accordingly, there is a risk of claims being brought in Vienna Convention and CSC countries for nuclear damage suffered in the UK. Ireland Because Ireland is not a contracting party to any international treaty concerning civil liability for nuclear damage, it is a “non-contracting state” under the Paris Convention. The Paris Convention and the NIA 1965 do not currently apply to any nuclear incidents occurring or damage suffered in a non-contracting state. However, assuming the 2004 Protocols are ratified and implemented pursuant to the 2016 Order, as Ireland does not have any operating nuclear installations, the Paris Convention and the NIA 1965 will apply to nuclear damage suffered in Ireland. As a consequence, the protections in the UK’s nuclear liability regime will extend to foreign-owned licensees and contractors operating in the UK’s nuclear market. However, all entities operating in the UK’s nuclear program are still at risk of claims being brought in Irish courts where there is no nuclear liability regime or nuclear liability treaty relations with the UK. Insurance Issues Arising From 2004 Protocols There has been wide concern as to the cost and availability to nuclear operators of insurance for the higher levels of liability required under the 2016 Order.43 According to a specialist report prepared by INDECS Consulting for DECC:44 coverage is likely to be available for higher liability caps; coverage is likely to be available for new categories of damage; and for an initial period of two to three years,45 coverage is unlikely to be available for the 30-year personal injury claims limitation period. The Explanatory Memorandum states that the UK Government will, subject to any EU or UK legal requirements such as State aid (see below), consider temporary arrangements to cover any insurance coverage gap on commercial terms.46 The 2016 Order contains a provision authorizing the Secretary of State to make such arrangements.47 The UK Government is reportedly in discussions with both Nuclear Risk Insurers (the “NRI”) (the UK nuclear insurance pool) concerning DECC’s provision of reinsurance to the NRI,48 and the European Commission regarding the State aid treatment of any UK Government proposal to cover the insurance coverage gap. At this stage, it appears possible that a system can be designed that avoids this reinsurance being classified as State aid. The UK Government has also stated that it will seek to draw on lessons learned by other contracting parties to the 2004 Protocols. Potential Impact of “Brexit” on UK’s Implementation of 2004 Protocols Regarding State aid, any dealings with the European Commission will inevitably be impacted by the UK’s recent referendum decision to leave the EU (the so-called “Brexit”). State aid is entirely a matter of EU law and is administered by the EU. As a result, Brexit creates greater uncertainty for the future application of the State aid regime in the UK, and by extension, to UK nuclear projects. There is currently no indication that the UK, which historically has had one of the strongest records of State aid compliance in the EU, will not comply with its existing treaty obligations or that it would retroactively change its approach to past State aid decisions. Further, Brexit is unlikely to affect the implementation of the 2004 Protocols as they should be ratified long before the Brexit process is completed. Nonetheless, while the future application of the EU’s State aid regime to the UK remains unclear, there are already a number of apparent considerations for future projects: the European Commission has indicated privately that it will strongly de-prioritize UK-related cases and focus its resources elsewhere. With respect to its proposed provision of reinsurance to the NRI, this may make it difficult for the UK Government and affected UK nuclear projects to engage with the European Commission and put greater pressure on those parties to consider their approach to State aid risks; when the UK does leave the EU, there is a wide variety of possible outcomes for the State aid regime. Nuclear projects relying on, inter alia, UK Government reinsurance solutions before this situation has been clarified will need to be structured to protect the enforceability of those terms against any regulatory uncertainty; and the UK was a major voice supporting nuclear power in the EU. Post-Brexit, there is potential for less sympathetic treatment of State aid for nuclear projects generally. Notwithstanding these risks, with respect to the UK Government’s reinsurance support specifically, any state support may only be required for a two to three-year period during which the private insurance market cannot provide coverage. Further, if this support is structured sensibly, it may be possible to avoid a State aid review, particularly since the European Commission will have little appetite to challenge the UK Government’s State aid analysis. For further discussion of these and other State aid issues potentially impacting future UK nuclear projects, please see here. What the 2004 Protocols and 2016 Order Mean for Industry To prepare for the ratification of the 2004 Protocols, licensees (whether nuclear plant operators, disposal site operators, nuclear material shippers or others) may take particular note of the increased extent and duration of a licensee’s potential liabilities. In order to comply, licensees will need to (and, where relevant, will need to ensure that their contractors and subcontractors) update their insurance and financial security arrangements to cover these increased potential liabilities and obtain approval of these arrangements from the Secretary of State. For other entities that are not the primary licensees, the 2004 Protocols and 2016 Order warrant attention, particularly for contractors and subcontractors doing business with licensees. For example, in order to avoid “liability gaps,” contractors and subcontractors will need to assess whether the nuclear liability indemnities from which they benefit under their existing supply and services contracts require amendment in order to cover the greater liability to which licensees will become subject. It would be equally prudent for commercial banks and lending institutions to review their lending policies and guidelines against the 2004 Protocols and the 2016 Order to reassess the risks to which they are potentially exposed through nuclear-related business in the UK.
In June, the General Counsel of the Federal Energy Regulatory Commission (FERC) and the Public Utility Commission of Texas (PUCT) submitted comments to the Commodity Futures Trading Commission (CFTC) opposing the CFTC’s proposed amendment to an order it issued in 2013.49 The amendment clarified that the five FERC-jurisdictional regional transmission organizations (RTOs), the independent system operators (ISOs) and the PUCT-jurisdictional Electric Reliability Council of Texas (ERCOT) covered by the 2013 Order are not exempt from the private right of action provided in Section 22 of the Commodity Exchange Act (CEA) for violating the CEA’s anti-manipulation and anti-fraud provisions.50 In commenting on the Amendment Order, FERC urged the CFTC to “interpret the CEA as “not applying to any contract or instrument traded in [RTO and ISO] markets pursuant to a FERC tariff.” Similarly, PUCT urged the CFTC to leave the 2013 Order “in its current form, thereby clarifying that [private claims for violations of the CEA] are precluded.” Background Under the CEA, as amended in 2010 by the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank”), the CFTC has exclusive jurisdiction with respect to accounts, agreements and transactions involving swaps or contracts of sale of a commodity for future delivery traded, executed and cleared on CFTC-regulated exchanges and clearinghouses,51 including for natural gas and electricity, for purposes of enforcement of the CEA’s provisions against fraudulent behavior and manipulation of markets. Dodd-Frank also sought to avoid jurisdictional disputes between the CFTC, FERC (which regulates wholesale sales of electricity in interstate commerce) and PUCT (which has jurisdiction over sales of electricity within ERCOT) by adding a specific provision to Section 4(c) of the CEA directing the CFTC to exempt from CFTC regulation those transactions made pursuant to a FERC-approved tariff or a PUCT protocol if the CFTC finds that such an exemption is in the public interest. In the 2013 Order, the CFTC granted exemptions from the provisions of the CEA and CFTC regulations, with the exception of the CFTC’s general anti-fraud and anti-manipulation authority, and scienter-based prohibitions under specified sections of the CEA. These exemptions involve the purchase or sale of “financial transmission rights,” “energy transactions,” “forward capacity transactions” and “reserve or regulation transactions” offered or sold in markets administered by six RTOs and ISOs – Midwest Independent Transmission System Operator, Inc. (MISO), ISO New England, Inc. (ISO-NE), PJM Interconnection L.L.C. (PJM), the California Independent System Operator Corporation (CAISO), the New York Independent System Operator, Inc. (NYISO) and ERCOT pursuant to a tariff or protocol that has been approved or permitted to take effect by FERC or the PUCT. In 2015, the CFTC issued a proposed order providing a similar exemption for transactions in the markets administered by the Southwest Power Pool (SPP), an RTO.52 However, the SPP Order proposed not to exempt SPP from the private right of action under Section 22 of the CEA for violations of the manipulation, fraud and scienter-based provisions. In the SPP Order, the CFTC explained that by enacting Section 22 of the CEA, Congress had intended to permit private parties to bring suit for fraud, manipulation and other scienter-based violations of the CEA as a means to address violations of the CEA as an alternative or supplement to CFTC enforcement action. The preamble to the SPP Order also suggested that the CFTC had intended the same result – permitting private lawsuits for violations of the CEA – in the 2013 Order. CFTC Amendment Order On May 16, the CFTC issued the Amendment Order, proposing to amend the 2013 Order to clarify that it does not exempt RTOs and ISOs from the private right of action provided in Section 22 of the CEA for violations of the CEA’s anti-fraud, anti-market manipulation provisions. According to the CFTC, a February 2016 decision by the US Court of Appeals for the Fifth Circuit led to its proposed amendment of the 2013 Order. The decision affirmed an order of the US District Court for the Southern District of Texas dismissing a lawsuit by Aspire Commodities, L.P. and Raiden Commodities, L.P. (“Aspire”) against GDF Suez Energy North American, Inc. and its subsidiaries (“GDF Suez”) for violating anti-manipulation provisions of the CEA.53 Aspire alleged that GDF Suez had manipulated the locational marginal price on the ERCOT grid to profit on its trades, violating the anti-manipulation provisions of the CEA. GDF Suez moved to dismiss the suit because of the 2013 Order which had exempted ERCOT from provisions of the CEA. The district court had granted the motion to dismiss. The Fifth Circuit affirmed the lower court’s decision, finding that while the 2013 Order clearly subjects ERCOT transactions to the anti-manipulation provision of the CEA, and that the CFTC expressly retained the authority to enforce this antimanipulation section, those ERCOT transactions are exempted from a private right of action under the CEA. Aspire had argued that under a proper interpretation of the 2013 Order, guided by the SPP Order, the private right of action under the CEA still applies to transactions in ERCOT. The court rejected Aspire’s argument because, among other things, it found that the CFTC’s statements in the preamble of the SPP Order “directly contradict” the “plain language” of the 2013 Order. In the Amendment Order, the CFTC states that although it did not intend to provide an exemption from the private right of action established in Section 22 of the CEA in the 2013 Order, the Fifth Circuit “held that this was the effect” of the 2013 Order. The CFTC contends that the existence of a private right of action is not inconsistent with or detrimental to cooperation between the CFTC and FERC, will not cause regulatory uncertainty or duplicative or inconsistent regulation and will not affect the jurisdiction of FERC or any relevant state regulatory authority. The CFTC argues that private claims under the CEA serve the public interest by empowering injured parties to seek compensation for damages where the CFTC lacks the resources to do so on their behalf and deters misconduct in maintaining the integrity of the markets subject to CFTC jurisdiction. The CFTC observes that the Federal Power Act (FPA) expressly prohibits private rights of action for fraud and manipulation with respect to the purchase or sale of electric energy subject to FERC’s jurisdiction, while the private right of action under Section 22 of the CEA was an integral part of the CEA’s enforcement and remedial scheme. The fact that Congress made different judgments with respect to private rights of action under the CEA and the FPA, the CFTC argues, does not amount to a conflict between the two statutes. FERC and PUCT Opposition to the Amendment Order In its comments, FERC opposes the CFTC’s proposed introduction to FERC jurisdictional markets of a private right of action under the CEA because it would upset the Congressionally mandated balance between FERC and the CFTC, would be inconsistent with Congressional intent and would conflict with the design of the FPA.” In 2005, FERC argues, Congress amended the FPA to prohibit energy market manipulation, gave FERC authority to enforce the anti-market manipulation provision, including the authority to impose significant civil penalties, and explicitly prohibited private rights of action for violation of the energy market manipulation prohibitions. According to FERC, this amendment of the FPA constituted a “statutory decision by Congress in favor of public enforcement by a specialized agency, rather than private enforcement through a generalist court.” FERC argues that introducing a private right of action to markets regulated by FERC via the CEA appears to be inconsistent with Congressional intent and would conflict with the design of the FPA. According to FERC, “[a]llowing private rights of action through the courts could frustrate the careful line Congress drew when establishing complaint proceedings under the FPA designed to balance the need for market certainty with the goal of consumer protection,” and “risks the potential of jurisdiction conflicts between the CFTC and FERC being disputed by private actors in court proceedings, than through the inter-agency cooperation that Congress intended.” In its comments, PUCT maintains that allowing private parties to litigate causes of action under Section 22 of the CEA could have harmful effects on the oversight authority of PUCT. It could also adversely affect administration of the ERCOT markets by allowing private claims to collaterally attack the rules that constitute the structure of a market’s regulatory scheme, and allow a private litigant to sue ERCOT directly for activities undertaken in ERCOT. PUCT also asserts that the scope of potential liability under Section 22 of the CEA is “incredibly broad” and could result in a potential private claim against ERCOT itself in a lawsuit brought under Section 22 of the CEA. In addition, PUCT contends that Aspire v. GDF Suez “provides an example of the potential confusion and harm that private claims under Section 22 of the CEA could inflict on the ERCOT market.” PUCT argues that the plaintiff in Aspire v. GDF Suez alleged that GDF Suez was able to submit offers for electricity in ERCOT with the intent to manipulate prices in the derivative commodity market because of PUCT’s “Small Fish Rule.” According to this rule, electricity generators controlling less than 5% of the total installed generating capacity in ERCOT do not have market power. PUCT contends that if activities undertaken in compliance with the Small Fish Rule were subject to judicial scrutiny under a CEA privateparty claim, then the federal proceeding could raise doubts about the prudence of relying on that rule. According to PUCT, the effect would be to impair a market rule that is designed to benefit electricity consumers. Additional Opposition to Amendment Order The Electric Power Supply Association (EPSA), the trade association representing electricity generators and marketers, also submitted comments opposed to the Amendment Order. EPSA argues that the CFTC’s proposal to clarify the 2013 Order would be harmful to the interests of electricity consumers affected by misconduct in RTO/ISO markets because a private lawsuit brought under Section 22 of the CEA cannot provide comprehensive relief that consumers may obtain through regulatory proceedings of the FERC or PUCT, such as resettling markets and refunds. EPSA also argues that allowing private rights of action under Section 22 of the CEA would impose unnecessary and excessive costs on electricity consumers, because the costs of Section 22 lawsuits would be passed on to consumers in electric bills and would foster opportunistic, meritless lawsuits that would upset the important balance between the RTO/ISO responsibilities to send price signals and ensure reliability by intervening in the market. In addition, the US members of the ISO/RTO Council (IRC) – CAISO, ERCOT, ISO-NE, MISO, NYISO, PJM and SPP – submitted comments asking that the CFTC not adopt its proposed amendment to the 2013 Order. The IRC states that the members of the IRC covered by the 2013 Order (i.e., MISO, PJM, ISO-NE, NYISO, CAISO and ERCOT) believe that neither they nor the transactions covered by the 2013 Order are subject to CFTC jurisdiction under the CEA, and that they requested the exemption provided in the 2013 Order in order to avoid litigating this and other related jurisdictional questions in court. The IRC argues that permitting private lawsuits is likely to have a number of additional unintended consequences that do not serve the public interest, including creating uncertainty about the legal status of the regulatory regimes that oversee ISORTO markets, and enabling private parties to supplant the jurisdiction of FERC and PUCT to determine appropriate market outcomes by permitting collateral attacks on transactions under FERC- or PUCT-approved tariffs or protocols. After considering the comments received in response to the Amendment Order and the SPP Order, the CFTC will issue final orders in those two proceedings.
Since 2012, the major opponent of new large-scale liquefied natural gas (LNG) export projects has been the Sierra Club. The Sierra Club has adopted a two-pronged approach in its opposition to LNG exports projects, opposing both authorizations granted by the Federal Energy Regulatory Commission (FERC) under Section 3 of the Natural Gas Act (NGA) to construct and operate facilities for the export of LNG and authorizations granted by the US Department of Energy Office of Fossil Energy (DOE/FE) under Section 3 of the NGA to export LNG to countries with which the US does not have free trade agreements that require “national treatment” for trade in natural gas. The Sierra Club has argued that in granting authority to construct LNG facilities and export LNG, FERC and DOE/FE have not complied with the requirements of the National Environmental Policy Act of 1968 (NEPA) by failing to consider the indirect, cumulative and nationwide environmental effects of increased natural gas production due to increased natural gas exports. In separate opinions issued on June 28, the US Court of Appeals for the District of Columbia Circuit denied the Sierra Club’s appeals of two orders issued by FERC authorizing the construction and operation of LNG facilities. The D.C. Circuit found that because DOE/FE – and not FERC – has jurisdiction to authorize exports of natural gas, including LNG, FERC does not have to consider the potential environmental effects of increased natural gas production due to greater natural gas exports resulting from the construction of LNG export facilities. The court’s decisions defer consideration of the Sierra Club’s arguments to cases challenging DOE/FE’s authorization of LNG exports. Background Section 3 of the NGA gives FERC exclusive jurisdiction to approve the construction and operation of LNG terminals, which include natural gas facilities located onshore or in state waters used to receive, unload, load, store, transport, gasify, liquefy or process natural gas that is exported to a foreign country from the US. FERC approves the siting, construction and operation of LNG terminals upon a finding that such activities are not inconsistent with the public interest. In addition, under NEPA, FERC is obligated to consider the potential environmental effects of its authorization to construct LNG terminals. Section 3 of the NGA also gives DOE/FE authority over exports of natural gas. Under Section 3(c) of the NGA, LNG exports to countries with which the US has free trade agreements that require “national treatment” for trade in natural gas are automatically considered in the public interest, and applications to export gas to such countries must be approved without modification or delay. Requiring “national treatment” means treating an imported good the same as a locally produced good once it enters a market. The US currently has such free trade agreements with Australia, Bahrain, Canada, Chile, Colombia, Dominican Republic, El Salvador, Guatemala, Honduras, Jordan, Mexico, Morocco, Nicaragua, Oman, Panama, Peru, Republic of Korea and Singapore. Authorization to export LNG to countries without such free trade agreements requires DOE/FE to find that the proposed exports are not inconsistent with the public interest. In making this determination, DOE/FE considers the domestic need for the natural gas proposed to be exported, whether the proposed exports pose a threat to the security of domestic natural gas supplies and other factors bearing on the public interest. DOE also must review the potential environmental effects of the proposed export under NEPA. FERC is the lead agency for conducting the environmental review of proposed LNG export projects under NEPA, and DOE/FE has been a participating agency in FERC’s environmental review. Once FERC issues its final environmental review document (either an Environmental Impact Statement or an Environmental Assessment), DOE/FE issues its own Record of Decision, making its own environmental determinations in connection with its export authorization. The Sabine Pass Case In the first case considered by the D.C. Circuit, Sierra Club v. FERC, Case No. 14-1249 (the “Sabine Pass Case”), Sierra Club challenged FERC’s 2014 order amending its 2012 orders authorizing the construction and operation of Trains 1-4 of LNG export facilities in Cameron Parish, Louisiana operated by Sabine Pass Liquefaction, LLC and Sabine Pass LNG, L.P. (the “Sabine Pass LNG Facility”). This resulted in an increase of four million tons per year of natural gas in the production capacity at the Sabine Pass LNG Facility. Sierra Club argued that in its NEPA analysis, FERC failed to consider the indirect environmental effect of increased US natural gas production induced by greater exports of US-produced LNG, and the increased air pollution resulting from rising coal use due to inflated natural gas prices caused by larger LNG exports. Sierra Club contended that FERC should have considered these indirect effects cumulatively with all pending and approved proposals for LNG export projects in the US. The D.C. Circuit found that, at bottom, Sierra Club’s challenge to FERC’s order relates to the potential environmental effects of greater natural gas exports from the Sabine Pass LNG Facility, but that FERC’s orders do not authorize Sabine Pass to increase exports from the Sabine Pass LNG Facility. The court agreed with FERC that DOE/FE alone has legal authority to authorize Sabine Pass to increase commodity exports of LNG, and therefore FERC did not need to consider the indirect effects of concern to the Sierra Club in its NEPA review. The court also said that Sierra Club is free to raise these issues in a challenge to DOE’s NEPA review of its export decisions. The Freeport Case In the second case, Sierra Club and Galveston Baykeeper v. FERC, Case No. 14-1275 (the “Freeport Case”), Sierra Club challenged FERC’s 2014 order authorizing Freeport LNG Development, L.P. to construct and operate facilities for the export of LNG at its existing LNG terminal in Texas (the “Freeport LNG Facility”). Sierra Club argued that contrary to its obligation under NEPA, FERC had failed to consider the indirect environmental effects of a possible increase in domestic natural gas production being induced by LNG exports from the Freeport LNG Facility and had failed to analyze the cumulative environmental effects of the Freeport LNG facilities with all of the proposed export projects in the US. The D.C. Circuit considered whether FERC discharged its duty under NEPA to adequately consider the indirect and cumulative environmental effects of authorizing the siting, construction, expansion and operation of the Freeport LNG Facility. As in the Sabine Pass Case, the court agreed with FERC that because DOE/FE alone has authority to authorize the export of any natural gas through the Freeport LNG Facility, FERC’s NEPA analysis did not have to address the indirect effects of the anticipated export of natural gas from the Freeport LNG Facility. As in the Sabine Pass Case, the D.C. Circuit’s decision defers consideration of the Sierra Club’s arguments to appeals of DOE/FE orders authorizing LNG exports to non-FTA countries. The Sierra Club petitioned the D.C. Circuit for review of one of DOE/FE’s orders authorizing the export of LNG to nonFTA countries from the Freeport LNG Facility. The Sierra Club did not, however, seek judicial review of DOE/FE’s orders authorizing the export of LNG to non-FTA countries from Trains 1-4 of the Sabine Pass LNG Facility.
In early August, Tesla Motors Inc., a manufacturer of advanced electric vehicles and battery energy storage systems, announced a deal to buy SolarCity Corporation, a developer of distributed energy resources, particularly solar and storage located behind a customer’s meter. Elon Musk, the CEO of Tesla, has described the merger of Tesla and SolarCity as combining energy storage and solar generation in one company that can create fully integrated residential, commercial and grid-scale products as “part of solving the sustainable energy problem.” Entities with interests in electric storage projects and companies, such as the merged Tesla and SolarCity, are advocating a wider role for storage in US wholesale electricity markets in a pending proceeding before the Federal Energy Regulatory Commission (FERC) involving the ability of energy storage resources to participate in markets operated by regional transmission organizations (RTOs) and independent system operators (ISOs) under existing RTO/ISO tariffs and market rules.54 Historically, electric storage has consisted of hydroelectric pumped storage projects, which pump water to higher-level reservoirs when electricity demand is low, and allow it to flow downhill through electricity-generating turbines when demand increases. However, over the past 15 years, new electric storage technologies, such as batteries, flywheels (mechanical devices that harness rotational energy to deliver instantaneous electricity), compressed air energy storage and electrochemical capacitors, have provided certain ancillary services to the electricity grid, including frequency regulation (which reconciles momentary differences caused by fluctuations in generation and loads), energy management, backup power, load leveling, voltage support and grid stabilization. In addition, according to the Energy Storage Association (ESA), energy storage systems currently make up approximately 2% of US electricity generation capacity. The US Energy Information Administration has reported that, while hydroelectric pumped storage made up 98% of total US electric storage capacity in 2015, between 2010-2015, non-hydroelectric storage doubled in electric power sector capacity from 160 MW to nearly 350 MW.
Large-scale deployment of electric storage resources is seen as a key to increasing the share of intermittent renewable energy resources, such as solar and wind, in the US electricity generation mix. In 2010, California enacted legislation directing the California Public Utilities Commission (CPUC) to determine appropriate targets, if any, for each load-serving entity (LSE) to procure viable and cost-effective energy storage systems and to adopt an energy storage system procurement target, if determined to be appropriate, to be achieved by each LSE by December 31, 2015, and a second target to be achieved by each LSE by December 31, 2020. The California legislature passed this law because, among other things, “[e]xpanding the use of energy storage systems can assist electrical corporations, electric service providers, community choice aggregators, and local publicly owned electric utilities in integrating increased amounts of renewable energy resources into the electrical transmission and distribution grid. . . .” The legislature also found that “[t]here are significant barriers to obtaining the benefits of energy storage systems, including inadequate evaluation of the use of energy storage to integrate renewable energy resources into the transmission and distribution grid through long-term electricity resource planning, lack of recognition of technological and marketplace advancements, and inadequate statutory and regulatory support.” In response to this legislation, the CPUC adopted an energy storage procurement framework in October 2013, establishing an energy storage target of 1,325 MW by 2020 for the three investor-owned public utilities subject to its jurisdiction – Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company, with installations required no later than the end of 2024. In April, FERC’s Office of Energy Policy and Innovation sent data requests to the six RTOs and ISOs subject to FERC jurisdiction (NYISO, ISO-NE, PJM, MISO, SPP and CAISO), seeking information about their tariffs and market rules that affect the participation of electric storage resources, which FERC has defined as “a facility that can receive electric energy from the grid and store it for later injection of electricity back to the grid.” According to FERC staff, this definition of electric storage resources includes all types of electric storage technologies, regardless of their size and storage medium, or whether they are interconnected to the transmission system, distribution system or behind a customer meter. In this proceeding, FERC staff is trying to determine whether barriers exist to the participation of electric storage resources in the capacity, energy and ancillary services markets operated by RTOs and ISOs that could lead to unjust and unreasonable rates for wholesale sales of electricity, which are prohibited by the Federal Power Act, and, if such barriers exist, whether any changes to RTO and ISO tariffs are necessary. FERC staff initiated the proceeding in light of, among other things, the numerous electric storage assets that have come on line in PJM, California’s initiatives related to that state’s renewable energy storage procurement mandate, and “key developments in the technology and cost-effectiveness of electric storage resources.” FERC also requested comments from the public on the responses submitted by the RTOs and ISOs, including specific examples of RTO/ISO rules that may facilitate or present barriers to electric storage participation in RTO and ISO markets. Each of the six FERC-jurisdictional RTOs and ISOs filed a response to FERC staff’s data requests in May, arguing that as a general matter, their tariffs and rules do not prohibit electric storage resources from participating in their markets. For example, PJM argues that its market rules are written to allow all resources to participate, regardless of technology, and as long as market participants can demonstrate that electric storage resources are able to meet the eligibility and performance criteria for each wholesale market, there is nothing prohibiting such resources from participating in PJM wholesale markets. PJM reports that the vast majority of non-hydroelectric pumped storage resources in PJM are batteries, most of which operate in PJM’s regulation market. According to PJM, there is currently a total of 5,814 megawatts (“MW”) of electric storage resources participating in PJM wholesale markets. Of this total, 5,537 MW of hydroelectric pumped storage resources, 245 MW of battery resources and 20 MW of flywheel resources are designated as generation resources, while 12 MW of battery resources are designated as demand-side resources. However, the RTOs and ISOs also indicate that based on their physical limitations, certain energy storage resources may not be eligible to participate in all RTO/ISO markets, may not qualify as a particular resource type under RTO/ISO tariffs and may not be eligible to provide particular services in RTO/ISO markets. This is due to the eligibility criteria and performance requirements set out in RTO/ISO tariffs with respect to providing services in the RTO/ISO market. These eligibility and performance requirements and qualification criteria include the ability to sustain output for a specified period of time, dispatchability, minimum offer size requirements and minimum capacity criteria. For example, SPP states that under its tariff, resources that cannot sustain output for 60 minutes are ineligible to qualify as sellers and register as a resource and that the minimum offer size for a resource to participate in SPP’s Integrated Marketplace is 0.1 MW. Entities with interests in electric storage submitted comments on the RTO/ISO responses in June. These entities generally argue that there are impediments to participation of electric storage resources in RTO and ISO markets, because RTO and ISO tariffs and markets were designed primarily for traditional electricity generators, and with respect to market participation and compensation, do not take into account the different operating characteristics of electric storage resources. In its comments, ESA contends that electric storage technologies are technically capable of providing any wholesale market service, but that the RTO/ISO responses to FERC’s data requests demonstrate that “electric storage has limited access to markets,” because “when wholesale electricity market designs and grid operations were originally developed, cost-effective electric storage was not contemplated.” ESA observes that only PJM and CAISO have designated a resource type that explicitly allows electric storage resources to participate in markets and does not limit them to certain services, while MISO, ISO-NE and NYISO tariffs explicitly allow electric storage resources to provide frequency regulation service, and electric storage resources that provide frequency regulation service are explicitly prohibited from providing other services. ESA also argues that some RTOs and ISOs have ambiguous tariffs with respect to the eligibility of electric storage resources to provide some market services. In order to remove these barriers, ESA asks FERC to require RTOs and ISOs to establish a resource type that ensures electric storage is eligible to participate in all markets and utilizes appropriate bid parameters and resource modeling for storage resources. ESA also asks FERC to ensure that qualification criteria and performance requirements enable storage resources to participate fully in markets. In its comments, Tesla states that its energy storage systems “can be utilized in wholesale energy markets, both as aggregated, distributed resources and as larger, centralized resources,” but argues that “market design-related barriers still preclude the full utilization and appropriate valuation of grid-scale energy storage systems in the US electricity grid.” According to Tesla, while the responses submitted by the RTOs and ISOs indicate that their tariffs do not condition participation in their markets based on resource types, “in reality, market product structures and market rules are still biased toward supporting conventional resources.” Tesla asks FERC to direct RTOs and ISOs to design their market products, such as capacity products, based on the needs of the electric system and not on operational parameters that were designed for conventional generators, clarify that electricity stored for resale is not an end-use load and thus should be only subject to pay the wholesale locational marginal price, and update generator interconnection procedures and agreements to allow and establish a process for interconnecting energy storage customers to accept charging restrictions in lieu of expensive interconnection upgrades where appropriate. SolarCity, which among other things offers large electricity customers solar plus storage connected to the distribution system, asserts that barriers exist to the eligibility of behind-the-meter energy storage resources to participate in wholesale electricity markets. According to SolarCity, existing RTO/ISO qualification criteria and performance requirements create barriers to the participation of many electric storage resources by unnecessarily requiring extended resource runtimes and baseline measurement methodologies that are not appropriate for energy storage resources. SolarCity also observes that behind-the-meter storage resources are largely classified as demand response resources that function by reducing a customer’s load, which unnecessarily limits the service provided to the level of the customer’s load, rather than the behindthe-meter resource’s capability. SolarCity contends that RTOs and ISOs should clearly define needs for wholesale energy markets, including those for energy, capacity and ancillary services, and allow any resource capable of fulfilling those needs to participate. In particular, SolarCity asks FERC to implement rules to ensure that behind-the-meter resources can participate to their full capability and are not limited by a specific customer’s load, and to ensure that the provision of one service in a wholesale market does not preclude the provision of other services when resources are technically capable of providing multiple services. Ice Energy installs, behind customer meters, ice batteries that charge by making ice during off-peak hours and discharges by using stored ice to cool buildings during peak air conditioning hours, integrated with a building’s cooling system. The company argues that FERC should adopt a technology-neutral policy and encourage ISOs and RTOs to adopt innovative tariff structures that allow for as many new technologies to participate in the markets as possible. Ice Energy argues that electric storage resources encompass aspects of both transmission and generation, and so should be viewed as a third regulatory category in their own right to compensate market participants for their resources. Storage resources, the company contends, can provide benefits to the electric grid-like demand response in that they can reduce load at peak times, but can also help by reducing load on demand. Viridity Energy, Inc., which develops and provides energy-related software, asks FERC to order the development of new or different market rules or product definitions where necessary to permit RTOs and ISOs to take advantage of the unique attributes of electric storage resources. For example, Viridity contends that a stand-alone solar resource may have a capacity factor of 30%, but that capacity factor can be significantly enhanced if paired with a properly sized storage device, and market rules should capture and pay for this enhancement. Viridity also argues that an unnecessarily large minimum registration amount can act as a barrier to entry for electric storage resources, and asks FERC to consider directing RTOs and ISOs to set minimums of 100 kW for those resources to participate in their markets. In addition, Viridity argues that electric storage resources can perform a transmission function as well as a generation function, and that RTOs and ISOs should permit these resources to be offered as transmission projects and allow the costs of storage as a transmission resource to be recovered through transmission tariffs. Typical market rules view capacity as a product which is always available and which can generate as much and as often as required by the RTO or ISO, Viridity argues. Although many electric storage resources cannot satisfy these requirements, they can contribute to the long-term reliability of the grid through the establishment of a more limited capacity product with different obligations and different pricing. Advanced Microgrid Solutions, Inc. (AMS), which designs, finances, installs and manages behind-the-meter energy storage systems for commercial, industrial and government buildings, argues that the most critical operational barrier to energy storage resources in wholesale markets is inaccurate compensation. AMS argues that electric storage resources can provide a number of different services traditionally provided by generation or in some cases loads, such as regulation service, reserve services and congestion management. Electric storage can also provide a number of different services to the host customer, such as load shifting to offset high energy prices and demand charge management. Yet, accounting practices and requirements prohibited developers from obtaining revenue with a resource-providing service under multiple classifications. As a result, AMS argues that a compensation model should be developed that accurately values the market and reliability services provided by energy storage, most importantly the elimination of any implicit storage penalties when a resource acts as a demand response resource. Utilities that participate in RTO and ISO markets also submitted comments on the RTO and ISO responses to FERC staff’s data requests. Many of these comments agreed with the view that electric storage resources should have a greater role in wholesale electricity markets. The Edison Electric Institute (EEI), the association of US shareholder-owned electric companies, suggests that RTO and ISO market rules be clarified or modified so that all resources capable of providing a service in a market be able to participate in that market. EEI also suggests that FERC should encourage multiple uses of electric storage resources, rather than limiting them to providing only regulation service. EEI also suggests that FERC require each RTO and ISO to provide additional explanation as to how different types of electric storage resources would actually register for and participate in each of the markets – capacity, energy and ancillary services – operated by the RTO or ISO. Duke Energy Corporation, which has a number of battery storage projects in the US that participate in RTO/ISO wholesale markets, argues that batteries should participate to the fullest extent possible in wholesale electricity markets, but that reliability should not be compromised in any way. According to Duke Energy, electric storage resources may not be costeffective when they compete with generation resources in RTO/ISO markets, because RTOs and ISOs segregate various RTO/ISO products and services and do not consider the benefits of electric storage resources as a whole. Duke Energy contends that RTOs and ISO interconnection rules and requirements should hold batteries that are functioning like generation to the same standards for interconnection as generation resources. American Electric Power Service Corp (AEP) argues, among other things, that current electricity services product designs vary among RTOs and ISOs and were established for specific operational needs, providing an incentive to resources to respond to pricing signals in a particular way to ensure grid reliability. AEP also argues that markets are only fair and nondiscriminatory if all service providers are required to fulfill the same requirements for the service they seek to provide. According to AEP, if an electric storage resource cannot qualify to provide an existing service, then service definitions and qualifications should not be changed for the sole purpose of incorporating more electric storage resources; rather, if there are characteristics of electric storage resources that are beneficial to operations or efficient markets that are not being recognized, then a new service could be developed. AEP further argues that electric storage resources should only be compensated for the services for which they qualify. Among other things, SCE asks FERC to provide clarity on the jurisdictional issue of wholesale and retail treatment and interconnection requirements for storage that participates in wholesale markets, noting that under current rules and tariffs, all energy used to charge a behind-the-meter-storage resource is state jurisdictional retail energy consumption and that currently there is no method in place to distinguish it if the energy used for changing a behind-the-meter storage device is then used for wholesale or retail service. SCE also asks FERC to confirm that any individual storage resource connecting to the distribution system that requires an interconnection agreement will continue to interconnect through a wholesale interconnection rather than through a state jurisdictional interconnection agreement. SCE also advocates several key principles in exploring the ability and opportunities of electric storage resources in wholesale markets, including that an electric storage resource connected to the distribution grid must accept the primacy of the safety and reliability function and be subject to operating instructions should its wholesale award from an ISO/RTO create reliability issues on the distribution grid. SCE further advocates that when participating in wholesale markets, an electric storage resource should be settled at the locational marginal price during the time and at the location of performance, and that an electric storage resource should not be allowed to charge at wholesale and then discharge to serve on-site retail load. Finally, SCE advocates that an electric storage resource may be compensated for multiple, distinct services provided simultaneously, but that these services must each have a distinct system need associated with it, and the electric storage resource may not be paid twice for the same service. FERC staff will review the information and comments submitted in the proceeding and determine whether additional action, such as a policy statement or notice of proposed rulemaking, is necessary.