Originally published May 23, 2022
Before the current decade is out, America will mark the centennial of federal regulation of electric utilities and natural gas. Countless innovations and social shifts have transformed the energy industry in the intervening century, perhaps most significantly the creation of the electrical grid, the extension of the world's largest system of pipelines, and the advent of market deregulation. But even bigger shifts lie ahead. Faced with the challenges of atmospheric greenhouse gas emissions and fossil fuel reliance, America must retool itself as a hydrogen economy.
America is usually an early leader in new energy technologies. But its robust energy infrastructure—legislatively and physically—can create bottlenecks that stand in the way of improvements. Hydrogen promises efficiency, portability, and abundance if it can be achieved without reliance on fossil fuels. But in order to achieve that promise, energy regulations must adapt. This report will examine the development of American energy regulation, current barriers facing alternative energy technologies, and opportunities to improve existing regulatory frameworks.
ORIGINS OF AMERICAN ENERGY INDUSTRY REGULATION
A. The Dream of a Hydrogen Economy and the Race to Integrate Renewables
Hydrogen is the simplest element, and the most abundant form of matter in the universe.[1] During the 2003 State of the Union address, President George W. Bush touted the idea of a "hydrogen economy," with cheap hydrogen and hydrogen fuel cell technology displacing fossil fuels.[2] Hydrogen is by many standards the only highly portable liquid storage medium for energy that can rival fossil fuels.[3] It is attractive for industrial, home, and transportation uses thanks to its flexibility and because it can be produced from diverse sources such as oil, natural gas, and biomass through steam reforming, but results in the lowest greenhouse gas emissions when produced through electrolysis—the splitting of water molecules—achieved with the use of electricity from renewable sources or nuclear power.[4] The combustion of hydrogen produces essentially no pollution, yielding only water and heat, thus avoiding the serious environmental risks of fossil fuels.[5]
Over recent decades, interest in hydrogen was spurred by two different objectives: energy independence and decarbonization.[6] Of the two, decarbonization to reduce reliance on fossil fuels, and achieve lower greenhouse gas emissions has emerged as the leading objective.[7] Hydrogen has a variety of advantages. When used in fuel cells, it can support vehicle mobility.[8] Compared with large fixed batteries or pumped storage facilities proposed to store renewable energy when the sun is not shining and the wind is not blowing, hydrogen promises extensive storage capacity.[9] Above all, it promises a long-term energy storage medium that can be transported by pipelines, trucks, or trains, and serve flexible roles in industry and consumer use.[10]
Hydrogen does face some drawbacks. The cheapest ways to produce hydrogen are with steam methane reforming and autothermal reforming, but both methods produce carbon emissions.[11] Hydrogen faces potential losses of up to forty-five percent during transfer through pipelines or conversion into electricity in fuel cells, compared with twelve percent losses through the direct production and transmission of electricity from renewable sources.[12] Additionally, hydrogen poses unique infrastructure challenges because it interacts with many steel alloys, causing metal embrittlement.[13]
Early innovation around hydrogen was dogged with concerns about safety and liability, because hydrogen is explosive.[14] However, concerns about hydrogen's combustible characteristics may be overblown, because it emits only one-tenth the radiative heat of a hydrocarbon fire.[15] Although hydrogen has faced some potential products liability barriers, that has not prevented California from introducing hydrogen fueling stations.[16]
Hydrogen technology faces the incumbency of fossil fuel technology, which remains economical and well-established throughout the world, as well as government policies promoting battery technology in lieu of hydrogen. The federal government and some state governments are promoting electric vehicles (EV) as an alternative to gasoline, diesel, and hydrogen cars to curb greenhouse gas emissions from transportation. But the addition of EVs is placing new strains on the electrical grid.[17] A typical EV needs thirty kilowatt hours of electricity to go 100 miles, equaling the average consumption of all appliances in a typical American home. Mass electrification of road transport would increase the nation's electricity demand by upwards of thirty-eight percent, prompting surging demand in some states with limited capacity, such as Maine which would need to expand its electrical resources by fifty-five percent.[18] In some states like California, the grid has capacity for EVs, but may not be well calibrated to handle sudden surges in demand. [19]
Electric utilities have emerged as major promoters of EVs, viewing the technology as a way to gin up substantial demand for electricity and grow revenues. In 2018, for instance, ten utilities sued the Trump administration, opposing plans to make greenhouse gas standards more lenient.[20] In some cases, EVs are also considered from a technical, rather than financial or environmental perspective. Vehicle-to-grid, also known as V2G technology would allow cars to charge during daylight hours, as a way to store electricity generated from renewable sources.[21]
Ultimately, batteries provide only limited energy storage capability compared with hydrogen.[22] Electricity alone from batteries or the grid is also ill-suited for applications like aviation or heavy industry. Therefore, a battery-based renewable energy future is unlikely to succeed, leaving hydrogen technology as the only viable alternative to fossil fuels.
B. The Advent of the Electrical Grid and Pipelines
The electrical grid and natural gas pipelines are both critical pieces of infrastructure for a hydrogen economy, supplying the electricity needed for electrolysis, and potentially transporting gaseous hydrogen—or natural gas feedstock. Energy regulation in the US involves dual-federalism, with the Federal Energy Regulatory Commission overseeing the electrical grid and interstate natural gas pipelines, and state public utility commissions controlling many elements of power production intrastate.[23] The Nuclear Regulatory Commission, for its part, oversees the licensing and monitoring of nuclear power plants.[24] Federal regulation is largely preeminent and in some spheres preempts state energy laws—a state of affairs that has existed since the early 20th century.
The Supreme Court pointed the way to federal regulation of electric power in its 1927 Public Utilities Commission v. Attleboro Steam and Electric Co. decision. [25] "It is conceded, rightly, that the sale of electric current by the Narragansett Company to the Attleboro Company is a transaction in interstate commerce, notwithstanding the fact that the current is delivered at the state line. The transmission of electric current from one state to another, like that of gas, is interstate commerce," indicated Justice Sanford, writing for the majority.[26] The case produced the so-called "Attleboro gap," with the Court indicating that the Commerce Clause prevented one state from regulating the rate charged by utility for sales of power to a utility in another state.[27] As a result, states could not directly regulate bulk sales of electricity with other states, and neither could the federal government without enabling legislation under the Commerce Clause.[28]
Responding to the gap, the New Deal era Congress enacted the Federal Power Act of 1935, expanding the preexisting 1920 Federal Water Power Act.[29] The proto-Keynesian regulatory bent of the Roosevelt administration promoted the creation of established monopolies and oligopolies to prevent what was viewed as dangerous competition. At virtually the same time as the Federal Power Act broadened the scope of authority granted to the Federal Power Commission, Congress also enacted the Public Utility Holding Company Act of 1935 (PUHCA), mandating that utilities above a certain size register with the Securities and Exchange Commission.[30]
After electrical utilities, regulation of natural gas soon followed. Throughout the 1930s, municipalities remained concerned about the monopolization of natural gas. Seeking to forestall common carrier requirements, natural gas companies sought regulation from the federal government, culminating in the passage of the Natural Gas Act of 1938.[31] At the start of World War II, the East Coast remained reliant on coastal transport of oil, or production of natural gas from coal at gasification plants. A total of fifty-five tankers were lost along the coast to Nazi submarines. Even before the U.S. entry into the war, two natural gas companies were trying to expand pipelines into the Southeast, but struggled with the lack of an eminent domain law in Georgia. Exploiting wartime conditions, Congress passed the short-lived Cole Act granting eminent domain powers for pipeline projects between 1941 and 1943.[32]
At war's end, the Texas Eastern Transmission Co. tried to repurpose the so-called "Inch Lines" to the Northeast for civilian uses, but faced pushback from state governments with entrenched coal interests. Natural gas had proven integral to powering many factories during the war, and crippling natural gas shortages in 1946 and 1947 spurred 50,000 layoffs when factories shut down. Congress passed eminent domain powers for natural gas pipelines in 1947.[33] Electricity and natural gas had become heavily regulated through the dual-federalism of the federal government and states, but a powerful set of federal laws meant that vertically integrated developers could readily extend electrical transmission lines and natural gas pipelines across state lines.
C. Market Deregulation for Electricity and Natural Gas
Although energy remains comparatively heavily regulated, contemporary efforts to create a hydrogen economy now take place in a fundamentally different regulatory framework than that which existed between the 1930s and the early 1980s. Following more than twenty years of relative steady state in the electricity and natural gas industries as the American electrical grid and natural gas infrastructure grew extensively, the 1970s brought a change in tenor from federal regulators.
The Supreme Court set the stage for deregulation of utilities in its 1973 Otter Tail Power Co. v. U.S. decision.[34] "There is nothing in the legislative history which reveals a purpose to insulate electric power companies from the operation of the antitrust laws," observed Justice Douglas, writing for the Court. [35] Otter Tail, a northern Midwest utility refused to wheel power to municipalities at the cheaper rates offered by the Bureau of Reclamation, but was compelled to by the Court.[36]
The Federal Power Commission, renamed during the 1970s as the Federal Energy Regulatory Commission (FERC), took advantage of the 1978 Public Utility Regulatory Policy Act to order wheeling of electricity from small generators. FERC shifted away from price regulation of individual firms, particularly with the advent of independent power generators in the 1980s.[37] Significantly, states were encouraged to shift away from block ratemaking to marginal cost pricing.[38] Local utilities, too, needed to connect to co-generators or small producers, purchasing electricity at "full avoided cost." [39]
Big developments followed with the Energy Policy Act of 1992, which granted FERC power to order companies that owned transmission to wheel power wholesale.[40] Between 1996 and 2000, FERC issued three significant orders to prevent monopoly control of transmission lines.[41] The most famous of the three, Order 888, requires electric utilities engaged in interstate commerce to file non-discriminatory tariffs, treating transmission and generating as different even if done by the same company through a process dubbed "functional unbundling." Order 888 was upheld in the courts in 2002, allowing the deregulatory process to carry on.[42]
Natural gas regulation underwent a similar significant change over virtually the same time period. In 1985, FERC began encouraging pipeline companies to provide open-access in exchange for easier project approval with Order 436.[43] Order 636 in 1992 made this a requirement.[44] FERC subsequently unbundled pipelines, separating pipelines from the gas production business, and kept only limited jurisdiction to review the price of natural gas sold across state lines.[45] These parallel deregulations culminated in the two energy markets being closely linked, yet electricity and natural gas operated on different schedules.[46] "Thus, when natural gas-fired electricity plants bid into a regional transmission organization (RTO) or Independent System Operation (ISO) auction indicating that they can provide a certain amount of electricity at a certain price, it can be difficult for these generators to properly formulate their bid when they do not know exactly how much gas they will have available to them at a particular price."[47] FERC rectified this with Order 809 in 2015, aligning timetables for both sectors.[48]
Deregulation has fundamentally changed the ways that electricity and natural gas are delivered to end customers, but deregulation is not universal within these sectors of the energy industry. In parallel with market deregulation, utilities now contend with Renewable Portfolio Standards, and associated renewable energy credits (REC) introduced by over half of states since the 1990s.[49] A typical approach requires a utility to get RECs for a portion of power generation from renewable sources like solar, wind, hydropower, or biomass; RECs may be coupled with a state clean energy target, and may or may not allow nuclear and natural gas to count.[50] Independent System Operators (ISO) and Regional Transmission Operators (RTO) have faced some challenges incorporating renewables.[51] Renewables, apart from nuclear, natural gas, and biomass, tend to be available independent of demand, thus forcing grid operators to curtail renewable inputs at certain times to sustain the grid.[52]
II. FROM LEGAL BARRIERS TO LEGAL SOLUTIONS: ACHIEVING A HYDROGEN ECONOMY
Continued innovation in the energy sector may one day yield high-efficiency, rapid recharge batteries that can store massive amounts of energy. At the current level of innovation, batteries are unreliable. Even if future innovations result in greater efficiency, liquid fuel or gas energy storage will likely promise greater storage and portability in the long-run.[53] With present technology, decarbonization of the economy cannot be achieved easily without a switch to hydrogen. In spite of acknowledged drawbacks like the explosiveness of hydrogen and metal embrittlement, a "hydrogen economy" holds greater promise than batteries, with the potential to apply to use cases as divergent as aviation and heavy industry. Therefore, policymakers should strive to support private sector innovation in this area. To achieve a hydrogen transition, careful analysis of existing laws is needed.
The most environmentally friendly production of hydrogen would involve nuclear, solar, wind, and geothermal.[54] Among fossil fuel sources, steam reformation of natural gas to produce hydrogen produces the fewest emissions and hydrogen can also be transported within pipelines in a blend, thereby reducing overall emissions where the gas is combusted, much like the inclusion of ethanol in gasoline.[55]
Barriers to renewable energy infrastructure commonly include problems with too many decisionmakers, and by extension too much veto power over projects. Nuclear power and wind likely face the greatest public opposition, with far less opposition to solar and geothermal. Nonetheless, even solar and geothermal technologies face some barriers of their own, such as regulatory confusion about whether geothermal resources are a mineral right or a water right, with implications for development.
Considering these factors, policymakers need to understand existing legal barriers to nuclear power, solar, wind, geothermal, natural gas distribution systems, and within the electrical transmission industry. Many reforms can be accomplished at the state level, but in rare circumstances surrounding nuclear power and offshore, enhanced federal preemption may be needed to achieve the potential of these technologies.
A. Nuclear
1. Barriers to Nuclear Power
Fears of nuclear reactor meltdowns and the safety of spent nuclear fuel are key concerns that motivate anti-nuclear sentiment among sections of the general public, as well as state and local governments.[56] Among alternative energy sources, nuclear power is uniquely bound up with administrative law, agency deference, and federal preemption. Nuclear power in the US is a regulated industry under the aegis of the Nuclear Regulatory Commission (NRC).[57] Implementing the National Environmental Policy Act (NEPA), NRC requires Environmental Impact Statements (EIS) as part of a Combined License Application (COL) and publishes permit and work authorization requests in the Federal Register.[58]
During the 1960s and 1970s, nuclear power was strongly favored by the federal government.[59] The Price-Anderson Act capped the liability for nuclear accidents at $560 million to encourage development.[60] The Supreme Court and circuit courts drew the bounds of federal preemption in several nuclear energy cases during the 1970s and early 1980s. At the high ebb of nuclear power in 1971, the Eighth Circuit held that federal law fully preempted state regulation over radioactive waste releases.[61]
However, ebullience about nuclear power faded in the late 1970s and by the 1980s nuclear power plant construction ground to a halt. This shift can be traced to a variety of events. The nuclear accident at Three Mile Island in 1979 harmed public confidence and resulted in a wave of project cancellations.[62] At the same time, electricity demand began to fall, the newly created Department of Energy signaled changes to reactor design, and the industry faced extensive cost overruns.[63] Additionally, in 1983, the Supreme Court held that states retain traditional responsibilities related to the regulation around electrical utilities such as determining market need, reliability, and costs, effectively allowing states to set high regulatory barriers on the construction of nuclear power plants.[64] Although NRC has exclusive jurisdiction over uranium enrichment facilities, nuclear imports and exports, and sea disposal of nuclear waste, NRC may enter into agreements with state governments about nuclear materials.[65] States may regulate the siting of nuclear facilities on economic rather than safety grounds and may ban uranium mining, because uranium mining is the only part of the nuclear fuel lifecycle not mentioned in the Atomic Energy Act.[66]
Even as new nuclear power plant projects stalled after the 1970s, the federal government took steps to promote nuclear energy. This has included Early Site Permits and Standard Design Certifications, fifty-fifty cost sharing arrangements, new tax credits, loan guarantees, and insurance subsidization.[67] Nonetheless, nuclear power plant construction has not recovered, except for a few new reactors licensed in the South in the late 2000s.[68]
The prevailing uncertainty brought on by regulatory changes in the early 1980s has chilled the entire nuclear market for decades.
2. Improving the Outlook for Nuclear Power
Nuclear power and natural gas are two of the most important elements of redundancy in the electrical grid. If nuclear power is replaced with intermittent wind, solar, and natural gas, greenhouse gas emissions rise—a pattern seen in California, Wisconsin, New England, and Florida after nuclear power plants closed in each location.[69] A strategy to enhance nuclear capacity may be to conduct new first-round operating license applications for modern reactors at the same location as existing plants as in the 2009 licenses issued in Georgia and Tennessee. A study of NGOs organizing against power projects found that only eight percent of antinuclear NGOs organized protests when projects were situated next to existing plants in areas already accustomed to nuclear power plants.[70]
Several times throughout recent decades, energy market participants have faced substantial stranded costs and engaged in costly lobbying efforts to recover these costs after the fact.[71] Congress attempted to address high fixed costs and regulatory uncertainty around nuclear power with the Energy Policy Act of 2005, providing a production tax credit for nuclear power plants.[72] However, the tax credit did not apply to applicants filing after 2008 and reduced in value over time.[73] Viewed through a tax policy lens, Congress could adjust this tax credit under § 45J, remove application cut-off deadlines, adjust the credit for inflation, and remove any megawatt limitations.[74] For a time, the Department of Energy maintained its Modified Accelerated Cost Recovery System, allowing renewable projects in service before January 1, 2018 to receive 50% first-year bonus depreciation.[75] Generous depreciation up-front, together with continued Price-Anderson liability caps, and full preemption of states in nuclear power plant approval would all benefit nuclear power as the redundant element in a hydrogen economy.
B. Solar
1. Barriers to Solar
Solar energy vies with wind as one of the most famous renewable energy sources, and apart from geothermal, might be one of the least controversial. It is also among the most distributed, because photovoltaic (PV) panels can be installed at houses and businesses far more cost effectively than wind or geothermal.[76] In an effort to promote solar, states have passed solar access laws together with other laws aimed at promoting solar energy.[77] Such laws create negative easements, so that neighboring properties cannot block sunlight to a particular property.[78] Most solar permitting is administered at the local level in the US, but this is often accompanied with complex filings and high costs. Some pro-solar city governments have developed over the counter permit purchases or made it illegal to forbid photovoltaic panels in historic districts.[79]
Solar has minimal entanglements with environmental law. Some solar components may fall under Resource Conservation and Recovery Act (RCRA) hazardous waste regulations.[80] Solar projects have been inextricably linked with federal investment tax credits, because solar is not always cost-effective without these supports. The industry was concerned about the expiration of credits in 2016, but Congress passed a renewal, and did so again in 2021, forestalling any changes to the present economics of photovaltaics.[81]
2. Improving the Outlook for Solar
RCRA concerns are likely too de minimus to merit any regulatory streamlining. There is no clear link between rates of solar growth and tax credit thresholds, which suggests that tax credits are neutral, or even of low relevance to solar projects.[82] As solar becomes more mainstream and competitive in the market, it is probably best to wind down tax credits, although continuing such measures until solar reaches some defined proportion of generation may be appropriate.
Solar is inherently cyclical throughout the day and unreliable like no other form of renewable energy, save for wind. However, it differs from wind because it is even more distributed. Solar panels are easy to install on buildings and are cheaper to install on a large scale than wind turbines. As a result, it is a popular choice among homeowners seeking more resilient power. However, homeowners often misconceive of solar panels as a way to operate independent of the grid, but in most cases this is not feasible so long as a house is integrated with the wider grid. Currently, customers with solar panels who are integrated with the grid cannot power their homes during a blackout.[83] Simultaneously, solar adds unreliability into the grid, heightening the risk of power surges or brownouts because sunlight tends to be unpredictable.
A resiliency approach in regulation is needed. In jurisdictions with interconnect requirements, this might allow utilities to limit interconnects to only solar customers with "smart" systems capable of responding to changes in grid demand.[84] It might also mean permitting microgrids and developing safeguards. For instance, Arizona regulators have adopted a system of inverters to put waste electricity into the ground during times of oversupply.[85]
C. Wind
1. Barriers to Wind
Wind is an abundant resource but requires extensive and costly infrastructure to generate large amounts of electricity. Since the 1980s, wind turbines have proliferated both onshore and offshore, as wind technology has become less expensive—and as governments have subsidized the installation of turbines. Offshore waters in the European Union have hosted vast wind farms for over two decades, financed by European governments.[86] Meanwhile, the US offshore wind has lagged behind due to fewer supports and a complicated regulatory landscape. December 12, 2016 marked an important milestone with the inauguration of the Block Island Wind Project off the coast of Rhode Island.[87] Offshore wind developers face significant regulatory and cost hurdles, acquiring offshore continental shelf (OCS) leases through an initial bid or subsequent assignment, securing rights of way for cables offshore and at connection points on the coast, and then installing expensive towers and turbines at sea.[88]
Offshore wind projects have bogged down in litigation, most famously Cape Wind in Massachusetts which stalled for nearly two decades in the courts.[89] At the time the project began, there was no federal permitting process for offshore wind, and the developers approached the Army Corps of Engineers for approval.[90] Bureau of Ocean Energy Management (BOEM) received permitting jurisdiction after the passage of the Energy Policy Act of 2005.[91] In spite of approval by the Massachusetts State Energy Siting Facilities Board and support from Obama-era Interior Secretary Ken Salazar, litigation-related delays halted the project and prompted the state's two largest utilities to back out of power purchase contracts.[92] By contrast, Maine provided a streamlined regulatory process as well as a statutory requirement that the Maine Public Utilities Commission acquire 25 MW of offshore power through a competitive power purchase agreement.[93] However, when Republican Larry LePage took over as governor from his Democratic predecessor, he ensured that the Maine legislature reconsidered the statute and issue a new request for proposals—Statoil, the offshore investor, backed out.[94]
Offshore wind is even more complicated in the Great Lakes.[95] States like Michigan and Wisconsin have massive wind energy potential, but at the beginning of the 2020s, Ohio's Icebreaker Wind Project was the only major development in the lakes.[96] States control offshore lands in the Great Lakes, but with significant involvement by federal stakeholders. Developers in Michigan offshore lands, for instance, need to contend with both the Michigan Department of Environmental Quality and the Army Corps of Engineers under the Great Lakes Submerged Lands Act.[97]
Because of the challenges of leasing offshore lands, some wind energy developers have increasingly turned to the idea of floating platforms.[98] Principle Power, in 2013, launched the first floating wind energy project in the nation in Coos Bay, Oregon, but failed to secure a power purchase agreement needed for Department of Energy financing.[99] Oregon faced unique geographic constraints because most of the state's population is centered in the Willamette Valley, and therefore transmission facilities over the Coast Range are limited.[100] Besides these transmission barriers, one analysis highlighted reasons for lack of offshore wind development in Oregon including: (1) a lower renewable power sourcing target than some Eastern states, (2) a five year, rather than three year REC creating less pressure for developments, (3) ad hoc mandates for utilities to buy power, and (4) need for additional state tax incentives.[101]
The Coastal Zone Management Act (CZMA) incorporates a notion of "federal-state collaboration," that allows states with a coastal zone management plan approved by the Department of Commerce to review offshore leasing by BOEM.[102] Although the Department of Commerce can override state complaints, the CZMA introduces another potential avenue to slow down offshore wind projects.[103]
Onshore wind has made more headway compared with offshore installations, because it does not face the same challenges with receiving offshore federal permitting, and placing power lines through coastal areas under the protection of the CZMA. However, onshore projects have still faced periodic opposition from environmental groups on Endangered Species Act grounds, due to concerns that spinning turbine blades will harm endemic flying species.[104] In other cases, groups have brought nuisance claims in courts, founded on noise and wind turbines as eyesores.[105] Much like offshore wind, the greatest challenges for onshore wind projects often arise at the state level from siting controls. Under Governor Deval Patrick, Massachusetts coupled the Global Warming Solutions Act of 2008 with the creation of the Advisory Energy Facilities Siting Commission.[106] A consulting report commissioned by the state indicated that challenges remained in the form of a megawatt generating requirement for a project to go through one-stop permitting (below a megawatt of capacity, projects needed to undergo local review), a lengthy appeals process, and options for preemption by local law.[107] By granting expedited permits only to projects with over 100 MW, Massachusetts effectively excluded most onshore wind projects.[108] Large onshore wind projects have faced similar challenges in Virginia. By the ten-year anniversary of its 2006 Energy Plan, Virginia still had only a single installed utility-scale wind power project in Botetourt County.[109]
American Indian reservations, particularly those sited in the West have significant wind power potential.[110] Because tribal governments are sovereign within the federal system, they are able to bypass other state and local land use restrictions.[111] However, tribes face a number of barriers related to onshore wind development. Principally, traditional FERC regulation disincentivized the construction of power lines to remote areas like reservations and problems remain with interconnect costs and lack of infrastructure.[112] Additionally, the federal governments control of tribal lands in trust can pose a substantial barrier to development.[113]
2. Improving the Outlook for Wind
Together with nuclear power, wind is one of the few cases where additional preemption may be needed. For the most part, onshore wind can and should be the domain of private landholders, local governments, and state public utility commissions. If a state wishes to limit the ease with which wind energy can be setup onshore, that is—for now—its prerogative. Plenty of Great Plains states and Texas have a combination of low population density, high winds, and an accommodating legal structure to supply wind power without Congress wading in to preempt state governments.
By contrast, there is a far clearer case for additional preemption of states in the realm of offshore wind. The Cape Wind debacle suggests that there are substantial regulatory hurdles to building offshore wind projects on the continental shelf. Federal preemption might take the form of eminent domain powers for developers, borrowing the concept from the 1947 Natural Gas Act amendment. This may raise entanglements with the CZMA, and therefore policymakers will need to analyze a new offshore wind bill alongside CZMA.
Federal and state lawmakers could take additional steps to promote wind development in the Great Lakes. In spite of advocacy by groups like Great Lakes Wind Council and bills introduced in 2010, Part 325 of the Great Lakes Submerged Lands Act still concerns riparian rights and dredging, rather than offshore wind development.[114]
Policymakers must consider the fact that offshore wind is still a new technology, with little regulatory or development track record. Preemption may need to be a part of the toolkit, but perhaps the "not in my backyard" residents of Massachusetts are atypical. Offshore wind, particularly beyond the horizon and situated near less developed stretches of coastline may prove more straightforward. In lieu of preemption, FERC and Bureau of Ocean Energy Management regulators may be able to achieve the same results through a better means of coordinating state and federal permitting.
D. Geothermal
1. Barriers to Geothermal
Geothermal energy is a promising renewable technology, but one which has attracted less attention from regulators than others. The US Geological Survey estimates that with current technology, the US has over 558,000 megawatts of geothermal potential.[115] Geothermal energy is produced by extracting hot deep groundwater or injecting surface water to a depth in the ground where it will be heated to produce steam. American geothermal resources are most promising in the seismically active Western states, but many of the same states suffer from water shortages.[116] An overlap of water laws and geothermal laws can sometimes create confusion. For instance, the Ninth Circuit in 1977 concluded that based upon the legislative history of the Stock-Raising Homestead Act, geothermal resources are essentially a mineral right and not a water right.[117] In states where geothermal resources are a mineral right, developers need to get a geothermal lease or permit that confers separate rights than the control of the surface land or surface water.[118] Additionally, treating geothermal resources as mineral rights may mean that developers incur other responsibilities to prevent "waste" that might damage neighboring rights holders, or obligations similar to oil and gas wells to avoid drilling too many wells and cap abandoned wells.[119]
The California Court of Appeals reached the same conclusion as the Ninth Circuit three years later in 1980, holding that deep geothermal resources constitute a type of mineral right.[120] By 2010, Nevada and Arizona distinguished geothermal water from other types of water use.[121] States like California centralize approvals for oil, gas, and geothermal projects under one agency: the California Department of Oil, Gas, and Geothermal Resources.[122] However, other states divide jurisdiction, as with Utah's division between Division of Water Rights and Board of Oil, Gas, and Mining.[123]
The geology of subsurface geothermal resources is often complicated, creating potential conflicts with oil and gas leases.[124] It is technologically feasible to reuse some oil and gas wells for geothermal projects. However, state laws which govern petroleum extraction projects remain unclear on several key questions: (1) whether it would constitute waste for a lessee to comingle hydrocarbon and geothermal production, (2) whether geothermal lessees could pool into abandoned wells, and (3) whether geothermal production would damage a hydrocarbon reservoir in a way that might constitute waste.[125] In addition to varying conceptions of geothermal resources, geothermal projects must meet NEPA and state environmental protection criteria, overcome modest risks of induced seismicity (earthquakes produced by lubricating small faults with water), and occasionally National Historic Preservation Act controls.[126]
2. Improving the Outlook for Geothermal
Federal and state lawmakers should clarify the status of geothermal fluids. Water injected at the surface from surface waters or near-surface groundwater would likely fall under existing water rights law. However, deep, briny fluids recovered from oil and gas projects and reinjected—or used in situ—would likely best be categorized as a mineral right. This type of distinction would prevent the misuse of scarce surface water and shallow groundwater throughout the American West.
Furthermore, adopting a legal interpretation of geothermal heat (and deep hydrothermal fluids) as mineral rights would create a legal regime where geothermal developers would be more careful to avoid waste that would harm neighboring wells, thereby improving the efficiency with which these resources are used.
NEPA and state equivalents create unnecessary regulatory burdens. The Bureau of Land Management signaled a commitment to regulatory streamlining in 2018, waiving the NEPA Environmental Assessment and Environmental Impact Statement requirement for oil, gas and geothermal projects.[127]
E. Natural Gas & Pipeline Development
1. Barriers to Natural Gas & Pipeline Development
Compared with many renewable energy sources, natural gas development faces few regulatory barriers due to a long history of federal preemption, that allows private developers to use eminent domain powers to construct pipelines. Although natural gas is non-renewable, natural gas pipeline infrastructure is relevant to a hydrogen economy because of its potential to provide feedstock for higher emission, but lower cost hydrogen, and because pipelines could be used to transport blends of hydrogen and natural gas to supply power plants, home heating, and heavy industry.
Prior to its mooting during the Trump administration, the Obama administration's Clean Power Plan called for states to use natural gas-fired power plants as a bridge fuel to more renewable sources.[128] Yet in spite of such encouragements and spate of deregulations since the 1990s, natural gas still faces hurdles at the state level. [129] Even with clean energy goals, regions like New England continue to import natural gas by ship rather than by pipelines from nearby onshore sources in Pennsylvania.[130]
The Natural Gas Act of 1938 (NGA) grants FERC considerable power over natural gas infrastructure, but the Energy Policy Act of 2005 contains a savings clause which means that states rights are not fully preempted under the Coastal Zone Management Act, Clean Water Act, and Clean Air Act.[131] Because federal law rather than state law usually governs, natural gas pipeline companies have been able to rapidly grow infrastructure between the 1950s and 1980s, and again during the recent shale gas boom, receiving approval, building, and putting into operation pipelines within little more than a year.[132] Nonetheless, environmental advocates are increasingly pressuring state and local governments to oppose pipeline projects, as evidenced by the opposition to Keystone XL and Dakota Access pipelines.[133] FERC is hard to influence with its more expansive control over interstate natural gas pipelines, but faces increased pressure to reject or modify natural gas pipeline projects in some states.[134] The Supreme Court weakened some of NGA's preemption in 2016, signaling that states may have more involvement in natural gas regulation in the future.[135]
2. Improving the Outlook for Natural Gas & Pipelines
A new Congressional Energy Policy Act could clarify and tighten FERC control over interstate natural gas pipeline projects, eliminating—or reducing the scope—of the savings clause. Klass and Rossi describe the savings clause approach to state environmental concerns as "costly and inefficient" because (1) FERC does not have a regular forum for state regulator input, and (2) the timing of the certificate process invites challengers.[136] New York was able to reject the Constitution Pipeline through recourse to federal environmental law, in-spite of prior approval by FERC.[137] It is important for Congress to keep eminent domain powers, and indeed clarify in a revised statute that these powers extend to dual-use natural gas and hydrogen pipelines, or pipelines transporting exclusively hydrogen.
F. Legal Challenges with Transmission: Imported Power, Net Metering, Long-Distance Lines, and Feed-In Tariffs
1. Electricity Imports: Policy Improvements
Electricity production remains largely a domestic industry, but the US has increased its imports from Canada and Mexico in recent decades. Electricity generated by large provincially controlled hydroelectric dams in Quebec, Ontario, Manitoba, and Newfoundland and Labrador is exported to New England, New York, and the Midwest, while the Canadian province of British Columbia imports electricity from the Pacific Northwest. Canada and the US had 60 electrical power linkages by 2015, consuming ten percent of all electricity produced in Canada, although only 1.6 percent of US retail sales.[138]
By contrast to its connections with the Canadian grid, the US has few interconnects with Mexico. The passage of the Electricity Public Service Act in 1992 by the Mexican federal government opened the door to expanded electricity sales, prompting some US utilities to build power plants in northern Mexico adjacent to Southern California. Exports from Mexico account for less than one hundredth of a percent of US electricity demand, centered on a few border regions like Southern California, El Paso, and South Texas.[139]
The dimensions of foreign electricity imports are narrow, but significant in the case of Canada for populous regions in the American Northeast, raising potential questions around the Foreign Sovereign Immunities Act of 1976.[140] Foreign state-owned enterprises have occasionally invoked sovereign immunity in an effort to avoid liability.[141] However, the Supreme Court has not clarified whether there is a distinction between national government owned state-owned enterprises, and those owned by sub-national authorities like the Canadian provinces. So far, power imports from North American neighbors has not generated much litigation or FSIA questions. In 2006, the Supreme Court did issue an opinion related to FSIA in context of a suit by the State of California against a British Columbian power producer. [142]
Current models across solar, geothermal, wind, and natural gas commonly promoted renewable energy-sourced electricity through state mandates.[143] While the goal of reducing carbon emissions is a noble one, mandates smack of market interference and have the potential to create market distortions. Particularly in the Northeast, mandates might create a dangerous reliance on energy imported from Canadian state-owned provincial electrical utilities.
State governments should develop comprehensive renewable energy plans that encompass nuclear and natural gas to maintain grid reliability. State emissions targets are appropriate if accompanied by RECs and tax credits, rather than mandates and power purchase requirements. State investments in training, research and development, or upgrades to port facilities to support offshore wind all merit consideration.[144]
Canada is the only foreign electricity market that US policymakers need to give real consideration to in long-term market planning. Because Canada has a similar legal system and a long-standing history of friendliness with the US, any electricity import issues could likely be solved through Canadian courts, US courts, binding arbitration, or diplomatic channels. Nonetheless, so long as any ambiguity exists surrounding FSIA, it would be sensible to craft a treaty with Ottawa guaranteeing a level footing for American customers purchasing from Canadian provincially-owned generators.
2. Net Metering
By the mid-2010s, over forty states had adopted some form of net metering, a scheme wherein customers with solar panels (and occasionally other renewable energy sources like geothermal and wind) sell surplus electricity back to utilities in exchange for credits to their electrical bill.[145] Net metering is an unusual system, because utilities pay customers for what competitors provide.[146]
Net metering policies vary widely between states. Developed through the Public Utility Regulatory Act, it is up to states to choose to offer net metering.[147] Some states exempt small, municipal, or low environmental impact utilities from paying out net metering disbursements to customers.[148] Utilities are increasingly challenging net metering in state public utility commissions.[149] The Arizona Corporation Commission, for instance, allowed up to five dollars a month in charges for energy sold to the utility and credited toward a solar owner's account, whereas the Utah Public Service Commission rejected such a proposal.[150]
Net metering is a regulatory riddle, and responses have encouraged it on resiliency grounds or rejected it as a form of unfair competition, subsidizing some ratepayers at the expense of others.[151] However, anticompetitive concerns are modest compared with the technical and market challenges that solar poses. As a result, the debate over net metering is one to be settled at the state level.
3. Feed-In Tariffs
Feed-in tariffs (FIT) are an element of state public policy copied from the European energy market.[152] Renewable power generators are guaranteed access to the grid and local electrical utilities are required to buy electricity above market rates—in contrast to market-rates common with RECs.[153] A FIT sets the price to be paid for renewable energy, how long that price will last for, and mandates that utilities must purchase this power.[154] Several states faced Commerce Clause challenges to FITs.[155] However, in 2010, FERC indicated that FITs are not preempted by the Federal Power Act.[156]
Much like net metering, FITs are perhaps best determined at the state level. Over the long-term, as renewable energy sources become more economical, state public utility commissions should phase out feed-in tariffs to reduce costs to end consumers and standardize on market-based policies.
4. Long-Distance Transmission Lines
As in the context of natural gas, a new Congressional Energy Policy Act could eliminate the states rights savings clause, retaining only a limited vestige for comment by citizens and state siting commissions. Klass and Rossi recognize the need to overcome growing state siting committee and eminent domain hurdles, particularly with a need to transmit electricity from resource-rich areas—like the Midwest wind or Southwest solar—to where the energy is consumed.[157] "[E]xperts contend that more interstate, regional transmission planning and construction is not only more cost-effective, but is necessary in light of the aging grid. . .the need for increased reliance on renewable energy resources. . .and the fact that transmission projects require as long as a decade to plan and construct."[158]
FERC approval of the Plains & Eastern Line over the objection of state regulators is an example of this model in action, but without accounting for state and local concerns projects are bound to bog down in litigation and public opposition.[159] Klass and Rossi propose the Great Northern Transmission line project from Manitoba into Minnesota as a well-rounded success story, wherein the developer conducted seventy-five public information workshops beginning before it filed its application.[160] The Great Northern model can be likened to Rhode Island's aforementioned offshore permitting experience. While tightening its control over siting, FERC could require something like this holistic outreach process to stakeholders prior to and during the permitting process.
III. CONCLUSION
The US has a once in a century opportunity to transform its energy system through regulatory streamlining. Policymakers must continue to examine ways to improve energy storage, whether through advanced battery technology, pumped storage, or hydrogen fuel cells—but existing barriers with these technologies mean that hydrogen is likely to be more viable than batteries across transportation, industry, and electrical power use cases. Nuclear and offshore wind face an unclear overlap of responsibilities between the federal government and states, which should be clarified to avoid lengthy litigation and problems with the CZMA. Federal preemption may be appropriate in the case of the two foregoing energy technologies, and may also be appropriate in the case of long-distance transmission lines and natural gas pipelines (particularly extended to dual-use natural gas and hydrogen pipelines). By contrast, most other renewable technologies are best regulated at the local level. States are adapting well to promote solar technology, but still present legal confusion with geothermal and impose some barriers on onshore wind. Policymakers must also consider the role of net metering, feed-in tariffs, depreciation schedules, and tax credits, applying comprehensive economic analysis to determine the best approach.
By reducing barriers to renewable energy and more traditional sources of redundancy like nuclear energy and natural gas, America can transition to a low-emission hydrogen economy.
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[144] Su, supra, note 57, at 306-7. [145] Brian Palumbo, Looking in the Side-View Mirror: Assessing the Current and Future State of the Solar Energy Industry as it Reaches the Mainstream, 41 Colum. J. Envtl. L. 183, (2016). [146] Palumbo, supra, note 111, at 211. [147] Heather Payne, A Tale of Two Solar Installations: How Electricity Regulations Impact Distributed Generation, 38 U. Haw. L. Rev. 135, 143 (2016). [148] Payne, supra, note 113, at 145. [149] Palumbo, supra, note 113, at 197-98. [150] Palumbo, supra, note 113, at 198. [151] Harvey L. Reiter & William Greene, The Case for Reforming Net Metering Compensation: Why Regulators and Courts Should Reject the Public Policy and Antitrust Arguments for Preserving the Status Quo, 37 Energy L.J. 373, 373 (2016). [152] Felix Mormann, Constitutional Challenges and Regulatory Opportunities for State Climate Policy Innovation, 41 Harv. Envtl. L. Rev. 189, 199-200 (2017). [153] Id. [154] Lincoln L. Davies, Reconciling Renewable Portfolio Standards and Feed-In Tariffs, 32 Utah Envtl. L. Rev. 311, 324 (2012). [155] Mormann, supra, note 117, at 193. [156] Cal. Pub. Utils. Comm'n., 133 FERC ¶ 61,059 (Oct. 20, 2010). [HOW TO PROPERLY CITE?] [157] Klass & Rossi, supra, note 99, at 443-44. [158] Id. [159] Klass & Rossi, supra, note 99, at 424-25. [160] Klass & Rossi, supra, note 99, at 477.
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